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TABLE OF CONTENTS
Item 8. Financial Statements and Supplementary Data
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K
 	 	 	
(Mark One)	 	 	

ý	
 	
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	

For the fiscal year ended December 31, 2014	

o	
 	
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	

For the transition period from          to        
	
Commission file number: 001-35167

Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
 	 	 	
Bermuda
(State or other jurisdiction of
incorporation or organization)	 	98-0686001
(I.R.S. Employer
Identification No.)	
Clarendon House
2 Church Street
Hamilton, Bermuda
(Address of principal executive offices)	 	HM 11
(Zip Code)	
Registrant's telephone number, including area code:+1 441 295 5950

Securities registered pursuant to Section 12(b) of the Act:
 	 	 	
Title of each class	 	Name of each exchange on which registered:	
Common Shares $0.01 par value	 	New York Stock Exchange	
          Securities registered pursuant to Section 12(g) of the Act: None

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

          Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ý     No  o

          Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  ý     No  o

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ý

          Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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  ý	 	Accelerated filer o	 	Non-accelerated filer o
(Do not check if a smaller reporting company)	 	Smaller reporting company  o	
          Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

          The aggregate market value of the voting and non-voting common shares held by non-affiliates, based on the per-share closing price of the registrant's common shares as of the last business day of the registrant's most recently completed second fiscal quarter was $1,506,618,282.

          The number of the registrant's Common Shares outstanding as of February 18, 2015 was 387,587,007.

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, 2014.

          Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.

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TABLE OF CONTENTS

        Unless otherwise stated in this report, references to "Kosmos," "we," "us" or "the company" refer to Kosmos Energy Ltd. and its subsidiaries. We have provided definitions for some of the industry terms used in this report in the "Glossary and Selected Abbreviations" beginning on page 2.

	 	 
	 	Page	 	
 	 	Glossary and Selected Abbreviations	 	 	2	 	
 	 	Cautionary Statement Regarding Forward-Looking Statements	 	 	6	 	
 	 	PART I	 	 	 	 	
Item 1.	 	Business	 	 	8	 	
Item 1A.	 	Risk Factors	 	 	42	 	
Item 1B.	 	Unresolved Staff Comments	 	 	73	 	
Item 2.	 	Properties	 	 	73	 	
Item 3.	 	Legal Proceedings	 	 	73	 	
Item 4.	 	Mine Safety Disclosures	 	 	73	 	
 	 	PART II	 	 	 	 	
Item 5.	 	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	 	 	74	 	
Item 6.	 	Selected Financial Data	 	 	76	 	
Item 7.	 	Management's Discussion and Analysis of Financial Condition and Results of Operations	 	 	78	 	
Item 7A.	 	Quantitative and Qualitative Disclosures About Market Risk	 	 	96	 	
Item 8.	 	Financial Statements and Supplementary Data	 	 	99	 	
Item 9.	 	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	 	 	143	 	
Item 9A.	 	Controls and Procedures	 	 	143	 	
Item 9B.	 	Other Information	 	 	144	 	
 	 	PART III	 	 	 	 	
Item 10.	 	Directors, Executive Officers and Corporate Governance	 	 	147	 	
Item 11.	 	Executive Compensation	 	 	147	 	
Item 12.	 	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	 	147	 	
Item 13.	 	Certain Relationships and Related Transactions, and Director Independence	 	 	147	 	
Item 14.	 	Principal Accounting Fees and Services	 	 	147	 	
 	 	PART IV	 	 	 	 	
Item 15.	 	Exhibits, Financial Statement Schedules	 	 	148	 	
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KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS

        The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.
 	 	 	
"2D seismic data"	 	Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.	

"3D seismic data"	
 	
Three-dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.	

"API"	
 	
A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.	

"ASC"	
 	
Financial Accounting Standards Board Accounting Standards Codification.	

"ASU"	
 	
Financial Accounting Standards Board Accounting Standards Update.	

"Barrel" or "Bbl"	
 	
A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.	

"BBbl"	
 	
Billion barrels of oil.	

"BBoe"	
 	
Billion barrels of oil equivalent.	

"Bcf"	
 	
Billion cubic feet.	

"Boe"	
 	
Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.	

"Boepd"	
 	
Barrels of oil equivalent per day.	

"Bopd"	
 	
Barrels of oil per day.	

"Bwpd"	
 	
Barrels of water per day.	

"Debt cover ratio"	
 	
The "debt cover ratio" is broadly defined, for each applicable calculation date, as the ratio of (x) total long-term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.	

"Developed acreage"	
 	
The number of acres that are allocated or assignable to productive wells or wells capable of production.	

"Development"	
 	
The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.	
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"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, (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.	

"E&P"	
 	
Exploration and production.	

"FASB"	
 	
Financial Accounting Standards Board.	

"Farm-in"	
 	
An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling costs of one or more specific wells or other performance by the assignee as a condition of the assignment.	

"Farm-out"	
 	
An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of the drilling costs of one or more specific wells and/or other work as a condition of the assignment.	

"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.	
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"Make-whole redemption price"	 	The "make-whole redemption price" is equal to the outstanding principal amount of such notes plus the greater of 1) 1% of the then outstanding principal amount of such notes and 2) the present value of the notes at 103.9% and required interest payments thereon through August 1, 2017 at such redemption date.	

"MBbl"	
 	
Thousand barrels of oil.	

"Mcf"	
 	
Thousand cubic feet of natural gas.	

"Mcfpd"	
 	
Thousand cubic feet per day of natural gas.	

"MMBbl"	
 	
Million barrels of oil.	

"MMBoe"	
 	
Million barrels of oil equivalent.	

"MMcf"	
 	
Million cubic feet of natural gas.	

"Natural gas liquid" or "NGL"	
 	
Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.	

"Petroleum contract"	
 	
A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.	

"Petroleum system"	
 	
A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.	

"Plan of development" or "PoD"	
 	
A written document outlining the steps to be undertaken to develop a field.	

"Productive well"	
 	
An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.	

"Prospect(s)"	
 	
A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.	

"Proved reserves"	
 	
Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4-10(a)(2).	
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"Proved developed reserves"	 	Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.	

"Proved undeveloped reserves"	
 	
Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.	

"Reconnaissance contract"	
 	
A contract in which the owner of hydrocarbons gives an E&P company rights to perform evaluation of existing data or potentially acquire additional data but may not convey an exclusive option to explore for, develop, and/or produce hydrocarbons from the lease area.	

"Resource Bridge"	
 	
Borrowing Base availability attributable to probable reserves and contingent resources from Jubilee Field Future Phases, Tweneboa, Enrenra 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 earth's subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.	

"Structural-stratigraphic trap"	
 	
A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.	

"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.	
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Cautionary Statement Regarding Forward-Looking Statements

        This annual report on Form 10-K contains estimates and forward-looking statements, principally in "Item 1. Business," "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this annual report on Form 10-K and the documents that we have filed as exhibits hereto completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward-looking statements may be influenced by the following factors, among others:

•
our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects;

•
uncertainties inherent in making estimates of our oil and natural gas data;

•
the successful implementation of our and our block partners' prospect discovery and development and drilling plans;

•
projected and targeted capital expenditures and other costs, commitments and revenues;

•
termination of or intervention in concessions, rights or authorizations granted by the governments of Ghana, Ireland, Mauritania, Morocco (including Western Sahara), Portugal, Senegal or Suriname (or their respective national oil companies) or any other federal, state or local governments or authorities, to us;

•
our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;

•
the ability to obtain financing and to comply with the terms under which such financing may be available;

•
the volatility of oil and natural gas prices;

•
the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;

•
the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;

•
other competitive pressures;

•
potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;

•
current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes;

•
cost of compliance with laws and regulations;

•
changes in environmental, health and safety or climate change laws, greenhouse gas regulation or the implementation, or interpretation, of those laws and regulations;

•
environmental liabilities;

•
geological, technical, drilling, production and processing problems;

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•
military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;

•
the cost and availability of adequate insurance coverage;

•
our vulnerability to severe weather events;

•
our ability to meet our obligations under the agreements governing our indebtedness, including the indenture governing the 7.875% Senior Secured Notes due 2021 ("Senior Notes");

•
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 and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this annual report on Form 10-K might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.

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PART I

Item 1.    Business

General

        Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara), Senegal and Suriname. Kosmos is listed on the New York Stock Exchange ("NYSE") and is traded under the ticker symbol KOS.

        Kosmos was founded in 2003 to find oil in under-explored or overlooked parts of West Africa. Members of the management team—who had previously worked together making significant discoveries and developing them in Africa, the Gulf of Mexico, and other areas—established the company on a single geologic concept that previously had been 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 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 102,000 Bopd for 2014.

        We have a dual focus of maximizing the value of our Ghana assets and increasing value through a high-impact exploration program. 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 pursuant to a plan of development which was approved by the Ministry of Energy in 2013, and the appraisal and development of our other Ghanaian discoveries. In our exploration portfolio we have a large inventory of leads and prospects. We plan to test the prospectivity of this inventory through the execution of a multi-year drilling program targeting high impact opportunities along the Atlantic Margin.

Our Business Strategy

Grow proved reserves and production through development, exploration and appraisal

        In the near-term we plan to grow proved reserves and production by further developing and debottlenecking the Jubilee Field and by completing the development of the TEN project, which is expected to deliver first oil in 2016 through a second, dedicated FPSO. Growth could also be realized, depending on the result of our ongoing assessment of commerciality and development over all or a portion of our Mahogany, Teak, Akasa and/or Wawa discoveries. In the longer-term, we plan to drill exploration prospects, with the intent to provide further growth.

Successfully open and develop our offshore exploration plays

        We believe the prospects and leads potentially existing offshore Ireland, Mauritania, Morocco (including Western Sahara), Senegal and Suriname provide a favorable opportunity to create substantial value. We anticipate drilling between two and four potentially play-opening exploratory wells per year, depending on the results of our analysis of seismic data, initial exploration drilling results, and availability of required equipment and services. Subject to the results of these exploratory wells,

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additional exploration and/or appraisal wells may be drilled. 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 technically-driven 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 these 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 in the Tano Basin offshore Ghana, resulting in the discovery of a significant new petroleum system, which the industry previously did not consider either prospective or commercially viable, and the accelerated development to first oil.

Focus on optimally developing our discoveries to initial production

        We focus on field developments designed to deliver early learnings and accelerate production. 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 numerous 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.

        The TEN development in Ghana is also being executed in a phased manner with the aim of achieving similar benefits. 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 is expected to be a 17-well development project with first oil anticipated to occur in the second half of 2016. Phase 2 of the development is expected to be a seven-well project with drilling anticipated to commence approximately one year after first oil from Phase 1. Both phases will focus primarily on development of the Enyenra and Ntomme oil fields.

        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

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operations expertise provided by these partners, as we have done with BP in Morocco and Chevron in Suriname and Mauritania.

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 oil potential.

        This was the case with respect to our Late Cretaceous core theme in West Africa, the niche in which we chose to initially focus. Many of our current licenses share similar geologic characteristics focused on untested structural-stratigraphic traps. In addition, our exploration portfolio includes sub-salt plays, which have been another recent successful play concept along the Atlantic Margin.

        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 oil has 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, 2014, we have approximately $1.9 billion of liquidity available to fund our opportunities. Additionally, we use derivative instruments to 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, 2014, we have hedged positions covering 10.2 million barrels of oil in 2015 and 2016, which provide partial downside protection should Dated Brent oil prices remain below our $85 to $94 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 region's subsurface, with careful consideration given to those attributes that lead to working petroleum systems. The process includes basin modeling to predict oil charge and fluid migration, as well as stratigraphic and structural analysis to identify reservoir/seal pair development and trap definition. This analysis integrates data from previously drilled wells and available seismic data. Importantly, this approach also takes into account a detailed analysis of geologic timing to ensure that we have an appropriate

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understanding of whether the sequencing of geological events could support and preserve hydrocarbon accumulation. Once an area is high-graded based on this play/fairway analysis, geophysical analysis is conducted to identify prospective traps of interest.

        Alongside the subsurface analysis, Kosmos performs an analysis of country-specific risks to gain an understanding of the "above-ground" dynamics, which may influence a particular country's relative desirability from an overall oil and natural gas operating and risk-adjusted return perspective. This iterative 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 revenues are generated from our operations offshore Ghana.

Ghana

        The West Cape Three Points ("WCTP") Block and Deepwater Tano ("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 and/or faults. Many of our discoveries have similar trap geometries.

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Our Ghanaian Discoveries

        Information about our Ghanaian discoveries is summarized in the following table.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Discoveries	 	License	 	Kosmos
Participating
Interest	 	Operator	 	Stage	 	Type	 	Year or Expected
Year of PoD
Submission	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Field Phase 1 and Phase 1A(1)	 	WCTP/DT(3)	 	24.1%(5)	 	Tullow	 	Production	 	Deepwater	 	 	2008/2011	(2)	
Jubilee Field subsequent phases	 	WCTP/DT(3)	 	24.1%(5)	 	Tullow	 	Development	 	Deepwater	 	 	2015	(7)	
TEN(1)	 	DT	 	17.0%(6)	 	Tullow	 	Development	 	Deepwater	 	 	2012	(8)	
Mahogany	 	WCTP	 	30.9%(4)	 	Kosmos	 	Appraisal	 	Deepwater	 	 	2015	(7)	
Teak	 	WCTP	 	30.9%(4)	 	Kosmos	 	Appraisal	 	Deepwater	 	 	2015	(7)	
Akasa	 	WCTP	 	30.9%(4)	 	Kosmos	 	Appraisal	 	Deepwater	 	 	2015	(7)	
Wawa	 	DT	 	18.0%(4)	 	Tullow	 	Appraisal	 	Deepwater	 	 	2016	 	

(1)
For information concerning our estimated proved reserves as of December 31, 2014, see "—Our Reserves."

(2)
The Jubilee Phase 1 and Phase 1A PoDs were approved by Ghana's Ministry of Energy in 2009 and 2012, respectively. Oil production from the Jubilee Field offshore Ghana commenced in November 2010, and we received our first oil revenues in early 2011.

(3)
The Jubilee Field straddles the boundary between the WCTP petroleum contract and the DT petroleum contract offshore Ghana. Consistent with the Ghanaian Petroleum Law, the WCTP petroleum contract and DT petroleum contract and as required by Ghana's Ministry of Energy, 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.

(4)
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.

(5)
These interest percentages are subject to redetermination of the participating interests in the Jubilee Field pursuant to the terms of the UUOA. GNPC exercised its WCTP petroleum contract and DT petroleum contract options, with respect to the Jubilee Unit, to acquire an additional unitized paying interest of 3.6% in the Jubilee Field. The Jubilee Field interest percentages give effect to the exercise of such option. Our paying interest on development activities in the Jubilee Field is 26.9%.

(6)
In February 2013, GNPC exercised its DT petroleum contract option, with respect to TEN, to acquire an additional paying interest of 5.0%. The TEN interest percentage gives effect to the exercise of such option. Our paying interest on development activities in TEN is 19%.

(7)
The revised Jubilee Full Field Development Plan ("JFFDP") is expected to be submitted during 2015, although we can give no assurance that such approvals will be forthcoming or in a timely manner or at all. The JFFDP is expected to cover all future development activity of the Jubilee Field and the development of the Mahogany, Teak and Akasa discoveries, should such discoveries be declared commercial.

(8)
The TEN PoD was approved by the government of Ghana in 2013 and is expected to deliver first oil in the second half of 2016.

        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 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 3,250 to 5,800 feet, which led to the decision to implement an FPSO based development. The FPSO is designed to provide water and natural gas injection to support reservoir pressure, to process and store oil and to export gas through a pipeline to the mainland. The Jubilee Field is being developed in a phased approach. The Phase 1 development focused on partial development of certain reservoirs in the Jubilee Field. The Kosmos-led Integrated Project Team ("IPT") successfully executed the initial 17 well development plan, which included nine producing wells, six water injection wells and two natural gas injection wells producing through subsea infrastructure to the "Kwame Nkrumah" FPSO. This initial phase provided additional subsea infrastructure capacity for further production and injection wells to be drilled in future phases of development.

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        The Phase 1A development provides further development to the currently producing Jubilee Field reservoirs. The Phase 1A development includes the drilling of eight additional wells consisting of five production wells and three water injection wells. Six wells (three producers and three water injection wells) are online, with production commencing in late 2012. Program execution is expected to be completed in 2015. Future phases include the further development of the three producing reservoirs and 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 2015 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. 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. 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.

        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 correcting the mechanical issues experienced in the Jubilee Field.

        Oil production from the Jubilee Field averaged approximately 102,000 barrels (gross) of oil per day during 2014. We submitted the JFFDP to Ghana's Minister of Energy in December 2012 and subsequently withdrew the application based on discussions with the government of Ghana. A revised JFFDP providing for full field development of the Greater Jubilee Field is expected to be submitted during 2015, although we can give no assurance that such approvals will be forthcoming in a timely manner or at all.

        We, as the Technical Operator of the Jubilee Field Phase 1 development, led the IPT, which consisted of geoscience, engineering, commercial, project services, and operations disciplines from within the Jubilee Unit partnership. We evaluated the resource base and developed an optimized reservoir depletion plan. This plan included the design and placement of wells and the selection of topside and subsea facilities. Our responsibilities also extended to project management of the design and implementation of the complete field development system. Our responsibility as Technical Operator of the Jubilee Field Phase 1 development was completed upon commissioning of the gas compression and injection systems and project administrative close out. The Unit Operator assumed responsibility for the day-to-day operations and maintenance of the FPSO as well as overseeing and optimizing the reservoir management plan based on field performance, including any well workover activity or additional in-fill drilling and subsequent phases.

DT 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 ranging from 3,300 to 5,700 feet. In November 2012, we submitted a declaration of commerciality and PoD over the TEN discoveries. In May 2013, the government of Ghana approved the TEN PoD. The discoveries are being jointly developed with shared infrastructure and a single FPSO.

        The TEN fields consist of multiple stratigraphic traps with reservoir intervals consisting of a series of stacked Upper Cretaceous Turonian-aged, deepwater fan lobes and channel deposits. Fluid samples

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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 project 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 with seven additional development wells expected to be drilled during Phase 2, with half of the wells designated as production wells and the remainder as water or gas injection wells to maximize recovery. Phase 2 drilling is anticipated to commence approximately one year after first oil from Phase 1. Both phases will focus primarily on the Enyenra and Ntomme oil fields.

        The TEN development is expected to deliver first oil in the second half of 2016 and is expected to increase towards the FPSO capacity of 80,000 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 startup.

        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 Ghana's Ministry of Energy within six months of the declaration of commerciality.

WCTP 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 4,100 to 5,900 feet. We believe the field is a combination stratigraphic-structural trap with reservoir intervals contained in a series of stacked Upper Cretaceous Turonian-aged, deepwater fan lobe and channel deposits. The Mahogany-3, Mahogany-4, Mahogany-5 and Mahogany Deep-2 wells have intersected multiple oil bearing reservoirs in a Turonian turbidite sequence. Fluid samples recovered from the wells indicate an oil gravity of between 31 and 37 degrees API.

        The Teak discovery is located in the western portion of the WCTP Block, northeast of the Jubilee Field. The field is approximately 31 miles offshore Ghana in water depths of approximately 650 to 3,600 feet. We believe the field is a structural-stratigraphic trap with an element of four-way closure. The Teak-1, Teak-2 and Teak-3 wells have intersected multiple oil and natural gas condensate bearing reservoirs in Campanian and Turonian zones. Fluid samples recovered from the wells indicate an oil gravity of between 32 and 39 degrees API and natural gas condensate gravity of between 40 and 45 degrees API. The Teak-4A appraisal well, completed in May 2012, encountered non-commercial reservoirs and accordingly was plugged and abandoned.

        The Akasa discovery is located in the western portion of the WCTP Block approximately 31 miles offshore Ghana in water depths of approximately 3,200 to 5,050 feet. The discovery is southeast of the Jubilee Field. We believe the target reservoirs are channels and lobes that are stratigraphically trapped. The Akasa-1 well intersected oil bearing reservoirs in the Turonian zones. Fluid samples recovered from the well indicate an oil gravity of 38 degrees API. The Akasa-2A appraisal well was drilled in May 2012.

        Following additional evaluation, a decision regarding the commerciality of our WCTP Block discoveries will be made by the WCTP Block partners. Should a discovery be declared commercial, we anticipate that it would be included in the JFFDP, which is expected to be submitted to the Ghanaian Ministry of Energy during 2015, although we can give no assurance that such approvals will be

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forthcoming in a timely manner or at all. We expect that any future development of the WCTP Block discoveries would be a subsea tie-back through the Jubilee FPSO.

License Areas

	 	Operator
(Participating
Interest)	 	Partners (Participating Interest)	
Ireland	 	 	 	 	
FEL 1/13	 	Kosmos (75%)	 	Antrim (25%)	
FEL 2/13	 	Kosmos (85%)	 	Europa (15%)	
FEL 3/13	 	Kosmos (85%)	 	Europa (15%)	
Mauritania(1)	 	 	 	 	
Block C8	 	Kosmos (90%)	 	SMHPM (10%)	
Block C12	 	Kosmos (90%)	 	SMHPM (10%)	
Block C13	 	Kosmos (90%)	 	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%)	
Senegal	 	 	 	 	
Cayar Offshore Profound	 	Kosmos (60%)	 	Petrosen (10%), Timis (30%)	
Saint Louis Offshore Profound	 	Kosmos (60%)	 	Petrosen (10%), Timis (30%)	
Suriname	 	 	 	 	
Block 42	 	Kosmos (50%)	 	Chevron (50%)	
Block 45	 	Kosmos (50%)	 	Chevron (50%)	

(1)
In February 2015, we entered into a farm-out agreement with an affiliate of Chevron covering our three license areas in Mauritania. The participating interest shown does not reflect the farm-out, as the agreement was not closed as of December 31, 2014. Once the farm-out agreement becomes effective, Kosmos, Chevron and SMHPM's participating interest in Block C8, Block C12 and Block C13 will be 60%, 30% and 10%, respectively.

        In August 2014, we entered into a farm-in agreement with Repsol Exploración, S.A. ("Repsol"), to acquire a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks offshore Portugal. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. After completing the acquisition, our participating interest in the blocks will be 31%. Repsol, Petróleos de Portugal—Petrogal, S.A. ("Galp") and Partex (Iberia) S.A. ("Partex") participating interest in the blocks will be 34%, 30% and 5%, respectively. Repsol will remain the operator.

Ireland

        We are the operator for Frontier Exploration Licenses ("FEL") 1-13, 2-13 and 3-13, which are located in the Porcupine Basin Offshore Ireland. We have identified the Porcupine Basin as an underexplored basin that has the potential for large hydrocarbon accumulations.

        The Porcupine Basin is a Jurassic aged rift basin located on the eastern Atlantic margin offshore Southwest Ireland. Previous exploration was focused on Jurassic and Tertiary aged sandstones located in the shallow water portions of the basin. These wells encountered Jurassic, Cretaceous and Tertiary

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reservoirs, Jurassic source rocks and oil and gas; however, no commercial developments have taken place in the basin. We have identified a number of Cretaceous age stratigraphic traps on 3D seismic data which have play potential similar to the features identified in our Atlantic Margin acreage.

        We completed acquisition of a 3D seismic survey measuring approximately 5,000 square kilometers over these blocks and in the surrounding area in October 2013. The processing of this seismic data was completed in late 2014.

        We have identified numerous prospects in our blocks and in 2015 we will continue to refine and assess the prospectivity of these license areas.

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 are adjacent to a proven petroleum system, 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 possible Cretaceous basin floor channels and fans in possible trapping geometries outboard of the Salt Basin. Cretaceous source rocks penetrated by wells and typed to oils in the Mauritania Salt Basin are believed to be the same age as those which charge other oil and gas fields in the Late Cretaceous of West Africa.

        A number of exploration wells have been drilled in the basin in shallow to moderate water depths and have resulted in oil and gas discoveries in both Tertiary and Cretaceous aged features. One of these, the Chinguetti Field is currently producing.

        Our acreage is located outboard of the producing area and range in water depth from 1,500 to 3,000 meters. These blocks cover an aggregate area of approximately 6.6 million acres. The blocks lie beyond the edge of the salt province on the basin floor where potentially reservoir bearing Mid to Late-Cretaceous aged sediments have been identified on vintage 2D seismic data.

        In May 2013, we completed a 2D seismic data acquisition program on approximately 6,000 line-kilometers, covering Blocks C8, C12 and C13. In November 2013, we completed a 3D seismic program of approximately 10,300 square kilometers over portions of Blocks C8 and C12. Processing of this seismic data was completed in 2014.

        This seismic data has helped identify numerous prospects in our blocks and we continue to interpret the data to assess the full prospectivity on our license areas in Mauritania. In November 2014, we drilled the top-hole section of the Tortue-1 exploration well in Block C8. We expect to complete the exploration well and have results during the first half of 2015.

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, which provide substantial exploration opportunities. The main play

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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 5,100 kilometers over the Cap Boujdour Offshore block. The processing of this seismic data is expected to be completed in 2015.

        The CB-1 exploration well on the Cap Boujdour Offshore block was spud in December 2014 to test the Al Khayr prospect (formerly named Gargaa). We expect well results during the first quarter of 2015.

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 7,800 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 4,300 square kilometers over the Tarhazoute Offshore and Essaouira Offshore blocks. The processing of this seismic data is expected to be completed in 2015.

        During 2014, we drilled the FA-1 exploration well in the Foum Assaka Offshore block. The FA-1 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.

        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 August 2014, we entered into a farm-in agreement to acquire a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks offshore Portugal. Certain governmental approvals and processes are still required to be completed before this acquisition is effective.

        Offshore Atlantic Portugal has been identified as an 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.

Senegal

        We are the operator for petroleum contracts covering the Cayar Offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal. The Cayar Offshore Profond and Saint Louis Offshore

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Profond petroleum contracts are in the Senegal River Mid-Cretaceous deep water system with multiple Lower Cretaceous source rocks, Albo-Cenomanian reservoir sands and are located south of the Mauritania Salt Basin, which has a working petroleum system. We completed a 3D seismic survey of approximately 7,000 square kilometers over the Cayar Offshore Profond and Saint Louis Offshore Profond blocks in January 2015.

        We have identified several prospects from existing 2D seismic data. As we continue to process and interpret data from the 3D seismic survey, we will continue to assess the prospectivity on the blocks.

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. The 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. This basin has experienced the same geologic forces which occurred along the transform margin of Africa. Therefore, we believe the basin's petroleum system to be analogous to petroleum systems seen in West Africa. A petroleum system in Suriname has been proven by the presence of onshore producing fields.

        We believe the play types offshore Suriname are relatively similar to those offshore West Africa and may contain subtle stratigraphic traps similar to those discovered offshore Ghana in the Jubilee Field. Target reservoirs are Upper and Middle Cretaceous age basin floor fans and mid-slope channel sands which may have good lateral continuity. The Tambaredjo and Calcutta Fields onshore Suriname demonstrate that a working petroleum system exists in the area. Geological and geochemical studies suggest the hydrocarbons in these fields were generated in 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. Suriname lies on the Atlantic transform margin of South America located between Guyana and French Guyana. The deep water basin is subdivided by the Demerara High, a platform area which separates the Suriname deep water basin from the French Guyana Basin where the Zaedyus oil discovery was made in Late Cretaceous sandstones in a stratigraphic trap. Block 42 and Block 45 are in the deep water area west of the Demerara Platform in the center of a thick Cretaceous and Tertiary succession associated with the post rift subsidence of the Atlantic continental margin.

        A number of onshore and shelf wells have encountered oil and, as previously noted, the Tamberedjo and Calcutta fields are currently producing. These fields are believed to be sourced from deep water Cretaceous source rocks. Seismic evidence suggests thick Late Cretaceous and Tertiary reservoir systems have been deposited in the deep water area and this stratigraphy may contain stratigraphic and structural trapping geometries analogous to both the Zaedyus and Jubilee discoveries.

        During 2012, we completed a 3D seismic data acquisition program which covered approximately 3,900 square kilometers over portions of Block 42 and Block 45 offshore Suriname. In August 2013, we completed a 2D seismic program of approximately 1,400 line kilometers over a portion of Block 42, outside of the existing 3D seismic survey. The processing of the seismic data was completed during 2014.

        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 2015.

Our Reserves

        The following table sets forth summary information about our estimated proved reserves as of December 31, 2014. See "Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)" for additional information.

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        All of our estimated proved reserves as of December 31, 2014 were associated with our Jubilee Field and the TEN development in Ghana. Our estimated proved reserves as of December 31, 2013 and 2012 were associated with our Jubilee Field in Ghana.

Summary of Oil and Gas Reserves

	 	2014 Net Proved Reserves(1)	 	2013 Net Proved Reserves(1)	 	2012 Net Proved Reserves(1)	 	
 
	 	Oil,
Condensate,
NGLs	 	Natural
Gas(2)	 	Total	 	Oil,
Condensate,
NGLs	 	Natural
Gas(2)	 	Total	 	Oil,
Condensate,
NGLs	 	Natural
Gas(2)	 	Total	 	
 
	 	(MMBbl)
	 	(Bcf)
	 	(MMBoe)
	 	(MMBbl)
	 	(Bcf)
	 	(MMBoe)
	 	(MMBbl)
	 	(Bcf)
	 	(MMBoe)
	 	
Reserves Category	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved developed	 	 	43	 	 	9	 	 	45	 	 	36	 	 	10	 	 	38	 	 	32	 	 	9	 	 	33	 	
Proved undeveloped(3)	 	 	30	 	 	6	 	 	31	 	 	9	 	 	1	 	 	9	 	 	10	 	 	1	 	 	10	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Total	 	 	73	 	 	14	 	 	75	 	 	45	 	 	11	 	 	47	 	 	42	 	 	9	 	 	43	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	

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

(2)
These reserves represent only the 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 is 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 of December 31, 2014, we recognized 27 MMBls of proved undeveloped reserves related to the TEN development, which is expected to begin first oil production in the second half of 2016.

        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.

        Changes for the year ended December 31, 2012, include a reclassification of 15 MMBbl of proved undeveloped reserves to proved developed reserves related to the successful remediation efforts in treating the near wellbore productivity issues on certain of the producing wells in the Jubilee Field and continued field development. These successful remediation efforts reduced the number of future drilling locations for the Jubilee Field (which included drilling locations related to our proved undeveloped reserves) and, as a result, approximately 5 MMBbl of proved undeveloped reserves from December 31, 2011 converted to proved developed reserves as of December 31, 2012. Additional changes include a decrease of 14 Bcf in proved gas reserves due to a decrease in our estimate of fuel gas utilized for operating the FPSO. As a result of the progress on the Phase 1A development, approximately 10 MMBbl of proved undeveloped reserves from December 31, 2011 were converted to proved developed reserves as of December 31, 2012. During the year ended December 31, 2012, we incurred $163.7 million of capital expenditures related to Phase 1A.

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        The following table sets forth the estimated future net revenues, excluding derivatives contracts, from net proved reserves and the expected benchmark prices used in projecting net revenues at December 31, 2014. 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 continuously remove associated natural gas in large quantities from the Jubilee Field, and the potential production restraints caused thereby, then the Jubilee Field's future net revenues discussed herein will be adversely affected.

	 	Projected Net
Revenues	 	
 
	 	(in millions
except $/Bbl)
	 	
Future net revenues	 	$	3,352	 	
​	​	​	​	​	
​	​	​	​	​	
​	​	​	​	​	
Present value of future net revenues:	 	 	 	 	
PV-10(1)	 	$	2,383	 	
Future income tax expense (levied at a corporate parent and intermediate subsidiary level)	 	 	—	 	
Discount of future income tax expense (levied at a corporate parent and intermediate subsidiary level) at 10% per annum	 	 	—	 	
​	​	​	​	​	
Standardized Measure(2)	 	$	2,383	 	
​	​	​	​	​	
​	​	​	​	​	
​	​	​	​	​	
Benchmark and differential oil price($/Bbl)(3)	 	$	101.55	 	

(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 levied under the WCTP and DT petroleum contracts), using prices based on an average of the first-day-of-the-months throughout 2014 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 or intermediate subsidiary level on future net revenues. However, it does include the effects of future tax expense levied at an asset level (in our case, it does include the effects of future Ghanaian tax expense levied under the WCTP and DT petroleum contracts). 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 levied under the WCTP and DT petroleum contracts), without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization,

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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 and intermediate subsidiary level on future net revenues. However, as we are a tax exempted company incorporated pursuant to the laws of Bermuda and as the Company's intermediate subsidiaries positioned between it and the subsidiary that is a signatory to the WCTP and DT petroleum contracts continue to be tax exempted companies, we do not expect to be subject to future income tax expense related to our proved oil and gas reserves levied at a corporate parent or intermediate subsidiary level on future net revenues. Therefore, the year-end 2014 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 $101.30/Bbl for Dated Brent at December 31, 2014. The price was adjusted for crude handling, transportation fees, quality, and a regional price differential. These adjustments are estimated to add a $0.25/Bbl premium relative to Dated Brent for the Jubilee Field. The adjusted price utilized to derive the Jubilee Field PV-10 is $101.55/Bbl. 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 $101.30/Bbl.

Estimated proved reserves

        Unless otherwise specifically identified in this report, the summary data with respect to our estimated net proved reserves for the year ended December 31, 2014 presented above has been prepared by Ryder Scott Company, L.P. ("RSC"), our independent reserve engineering firm, and for the years ended December 31, 2013 and 2012 presented above 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, 2014 are based on costs in effect at December 31, 2014 and the 12-month unweighted arithmetic average of the first-day-of-the-month price for the fiscal year ended December 31, 2014, 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.

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Independent petroleum engineers

Ryder Scott Company, L.P.

        RSC, our independent reserve engineers for the year ended December 31, 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 year ended December 31, 2014, we engaged RSC to prepare independent estimates of the extent and value of the proved reserves of certain of our oil and gas properties. These reports were prepared at our request to estimate our reserves and related future net revenues and PV-10 for the periods indicated therein. Our estimated reserves at December 31, 2014 and related future net revenues and PV-10 at December 31, 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, 2014 reserve report was completed on January 21, 2015, and a copy is included as an exhibit to this report.

        In connection with the preparation of the December 31, 2014 reserves report, RSC prepared its own estimates of our proved reserves. In the process of the reserves evaluation, RSC did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of RSC which brought into question the validity or sufficiency of any such information or data, RSC did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. RSC independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of "reasonable certainty," as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(2) of Regulation S-X. RSC issued a report on our proved reserves at December 31, 2014, based upon its evaluation. RSC's primary economic assumptions in estimates included an ability to sell Jubilee Field oil and TEN project oil at a price of $101.55/Bbl and $101.30/Bbl, 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 years ended December 31, 2013 and 2012, 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, 2012 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.

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        In connection with the preparation of the December 31, 2013 and 2012 reserves reports, 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 and operating conditions, consistent with the definition in Rule 4-10(a)(2) of Regulation S-X. NSAI issued a report on our proved reserves at December 31, 2013 and 2012, 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 and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have proved effective by actual comparison of production from projects in the same reservoir interval, an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

        In order to establish reasonable certainty with respect to our estimated proved reserves, RSC 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 technical services team, we currently maintain an internal staff of ten 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 technical services 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.

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        The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report incorporated herein is Mr. Guadalupe Ramirez. Mr. Ramirez has been practicing consulting petroleum engineering at RSC since 1981. Mr. Ramirez is a Licensed Professional Engineer in the State of Texas (No. 48318) and has over 35 years of practical experience in petroleum engineering. He graduated from Texas A&M University in 1976 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Ramirez meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

        The Audit Committee provides oversight on the processes utilized in the development of our internal reserve and resource estimates on an annual basis. In addition, our technical services 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, 2014 for the countries in which we currently operate.

	 	Developed Area
(Acres)	 	Undeveloped Area
(Acres)	 	Total Area (Acres)	 	
 
	 	Gross	 	Net(1)	 	Gross	 	Net(1)	 	Gross	 	Net(1)	 	
 
	 	(In thousands)
	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Unit	 	 	27.1	 	 	6.5	 	 	—	 	 	—	 	 	27.1	 	 	6.5	 	
West Cape Three Points(2)	 	 	—	 	 	—	 	 	101.4	 	 	31.3	 	 	101.4	 	 	31.3	 	
Deepwater Tano(2)	 	 	—	 	 	—	 	 	137.8	 	 	23.4	 	 	137.8	 	 	23.4	 	
Ireland	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
FEL 1/13	 	 	—	 	 	—	 	 	259.9	 	 	194.9	 	 	259.9	 	 	194.9	 	
FEL 2/13	 	 	—	 	 	—	 	 	189.8	 	 	161.3	 	 	189.8	 	 	161.3	 	
FEL 3/13	 	 	—	 	 	—	 	 	193.2	 	 	164.2	 	 	193.2	 	 	164.2	 	
Mauritania(3)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Block C8	 	 	—	 	 	—	 	 	2,940.6	 	 	2,646.5	 	 	2,940.6	 	 	2,646.5	 	
Block C12	 	 	—	 	 	—	 	 	1,748.3	 	 	1,573.4	 	 	1,748.3	 	 	1,573.4	 	
Block C13	 	 	—	 	 	—	 	 	1,927.4	 	 	1,734.7	 	 	1,927.4	 	 	1,734.7	 	
Morocco (including Western Sahara)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cap Boujdour	 	 	—	 	 	—	 	 	5,502.5	 	 	3,026.4	 	 	5,502.5	 	 	3,026.4	 	
Essaouira	 	 	—	 	 	—	 	 	2,171.2	 	 	651.4	 	 	2,171.2	 	 	651.4	 	
Foum Assaka	 	 	—	 	 	—	 	 	1,199.6	 	 	359.0	 	 	1,199.6	 	 	359.0	 	
Tarhazoute	 	 	—	 	 	—	 	 	1,915.9	 	 	574.8	 	 	1,915.9	 	 	574.8	 	
Senegal	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cayar Offshore Profound	 	 	—	 	 	—	 	 	1,950.9	 	 	1,170.5	 	 	1,950.9	 	 	1,170.5	 	
Saint Louis Offshore Profound	 	 	—	 	 	—	 	 	2,338.4	 	 	1,403.0	 	 	2,338.4	 	 	1,403.0	 	
Suriname	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Block 42	 	 	—	 	 	—	 	 	1,526.1	 	 	763.1	 	 	1,526.1	 	 	763.1	 	
Block 45	 	 	—	 	 	—	 	 	1,266.7	 	 	633.3	 	 	1,266.7	 	 	633.3	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Total	 	 	27.1	 	 	6.5	 	 	25,369.7	 	 	15,111.2	 	 	25,396.8	 	 	15,117.7	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	

(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 and the TEN project, which are

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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 phase 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 phase.

(3)
In February 2015, we entered into a farm-out agreement covering our three license areas in Mauritania. The net acres shown do not reflect the farm-out, as the agreement was not closed as of December 31, 2014. Once the farm-out agreement becomes effective, our estimated net acres in the Block C8, Block C12 and Block C13 are 1,764.3 thousand acres, 1,049.0 thousand acres and 1,156.5 thousand acres, respectively.

        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 offshore Portugal. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. After completing the acquisition, our participating interest in the blocks will be 31%. The gross and net undeveloped area will be 3,004.8 thousand acres and 931.5 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, 2014:

	 	Productive
Oil Wells	 	Productive
Gas Wells	 	Total	 	
 
	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	
Ghana—Jubilee Unit	 	 	23	 	 	5.52	 	 	—	 	 	—	 	 	23	 	 	5.52	 	
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Drilling activity

        The results of oil and natural gas wells drilled and completed for each of the last three years were as follows:

	 	Exploratory and Appraisal Wells(1)	 	Development Wells(1)	 	 

 
	 	Productive(2)	 	Dry(3)	 	Total	 	Productive(2)	 	Dry(3)	 	Total	 	 

 
	 	 	 	 	 	 	 	 	 	 	 	 	 	Total
Gross	 	Total
Net	 	 	 	 	 	 	 	 	 	
 
	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	 	 	 	 	 	 	 	 	 	 	 	 	
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	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
N'dian 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	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	
Year Ended December 31, 2012	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Unit	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	5	 	 	1.20	 	 	—	 	 	—	 	 	5	 	 	1.20	 	 	5	 	 	1.20	 	 	 	 	 	 	 	 	 	
West Cape Three Points	 	 	—	 	 	—	 	 	1	 	 	0.31	 	 	1	 	 	0.31	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1	 	 	0.31	 	 	 	 	 	 	 	 	 	
Deepwater Tano	 	 	—	 	 	—	 	 	1	 	 	0.18	 	 	1	 	 	0.18	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1	 	 	0.18	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	
Total	 	 	—	 	 	—	 	 	2	 	 	0.49	 	 	2	 	 	0.49	 	 	5	 	 	1.20	 	 	—	 	 	—	 	 	5	 	 	1.20	 	 	7	 	 	1.69	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	

(1)
As of December 31, 2014, 10 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 17 development wells awaiting completion. These wells are shown as "Wells Suspended or Waiting on Completion" in the table below.

(2)
A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled.

(3)
A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be a productive well, as opposed to the year the well was drilled.

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        The following table shows the number of wells that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of December 31, 2014.

	 	Actively Drilling or
Completing	 	Wells Suspended or
Waiting on Completion	 	
 
	 	Exploration	 	Development	 	Exploration	 	Development	 	
 
	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	
Ghana	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Jubilee Unit	 	 	—	 	 	—	 	 	1	 	 	0.24	 	 	—	 	 	—	 	 	2	 	 	0.48	 	
West Cape Three Points	 	 	—	 	 	—	 	 	—	 	 	—	 	 	9	 	 	2.78	 	 	—	 	 	—	 	
TEN	 	 	—	 	 	—	 	 	1	 	 	0.17	 	 	—	 	 	—	 	 	15	 	 	2.55	 	
Deepwater Tano	 	 	—	 	 	—	 	 	—	 	 	—	 	 	1	 	 	0.18	 	 	—	 	 	—	 	
Morocco (including Western Sahara)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cap Boujdour	 	 	1	 	 	0.55	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
Mauritania	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Block C8(1)	 	 	1	 	 	0.90	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Total	 	 	2	 	 	1.45	 	 	2	 	 	0.41	 	 	10	 	 	2.96	 	 	17	 	 	3.03	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	

(1)
In February 2015, we entered into a farm-out agreement covering our three license areas in Mauritania with Chevron. Once the agreement becomes effective and if Chevron exercises their option to participate in the Tortue-1 exploration well, our net interest in the well will be 60%.

Domestic Supply Requirements

        Many of our petroleum contracts or, in some cases, the applicable law governing such agreements, grant a right to the respective host country to purchase certain amounts of oil 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 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. 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 in December 2008 to acquire an additional paying interest of 2.5% in the Jubilee Field development (see "—Jubilee Field Unitization"). 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. Furthermore, it is obligated to pay 10% of the production costs of the Jubilee Field development, as allocated to the WCTP Block. In August 2009, GNPC notified us and our unit partners it would

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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 GNPC's production revenues under the terms of the WCTP petroleum contract. Kosmos is required to pay a fixed royalty of 5% and a sliding-scale royalty ("additional oil entitlement") which escalates as the nominal project rate of return increases. These royalties are to be paid in-kind or, at the election of the government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level.

        The WCTP petroleum contract has a duration of 30 years from its effective date (July 2004); however, in July 2011, at the end of the seven-year exploration phase, 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 phase. Effective January 14, 2014, the Ministry of Energy and GNPC entered into a Memorandum of Understanding with Kosmos Energy, on behalf of the 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 Energy 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 Energy and GNPC have agreed such WCTP petroleum contract rights to negotiate extend from July 21, 2011 until such time as either a new petroleum agreement 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 PetroSA's participating interests are 18%, 18%, 50.0% and 4.0%, 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 pay 10% of the production costs of the Jubilee Field development, as 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 GNPC's production revenues under the terms of the DT petroleum contract. Kosmos is required to pay a fixed royalty of 5% and an additional oil entitlement which escalates as the nominal project rate of return increases. These royalties are to be paid in-kind or, at the election of the government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level.

        In January 2013, at the end of the seven-year exploration phase, 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. Our existing Wawa discovery within the DT Block was not subject to relinquishment upon expiration of the exploration phase of the DT petroleum contract, as the DT petroleum contract remains in effect after the end of the exploration phase while commerciality is

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being determined. Additionally, the TEN development project was not subject to relinquishment. The Ghanaian Petroleum Law and the WCTP and DT petroleum contracts form the basis of our exploration, development and production operations on these 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 Ghana's Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. A Pre Unit Agreement was agreed to between the contractors groups of the WCTP and DT Blocks in 2008, with a more comprehensive unit agreement, the UUOA, agreed to in 2009 which govern each party's respective rights and duties in the Jubilee Unit. Tullow is the Unit Operator, while Kosmos was the Technical Operator for the initial development of the Jubilee Field. The Jubilee Unit holders' interests are subject to redetermination in accordance with the terms of the UUOA. As a result of the initial redetermination process completed in October 2011, the tract participation was determined to be 54.4% for the WCTP Block and 45.6% for the DT Block. Our Unit Interest was increased from 23.5% to 24.1%. The accounting for the Jubilee Unit is in accordance with the redetermined tract participation stated. Although the Jubilee Field is unitized, Kosmos' participating interests in each block outside the boundary of the Jubilee Unit remains 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, 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 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 of costs incurred from the effective date of the contract through the closing date. Cairn will fund Kosmos' share of one exploration well capped at $100.0 million. In the event the exploration well is determined to be a potentially commercial discovery, Cairn will pay 200% of its share of costs on two appraisal wells capped at $100.0 million per well. After giving effect to the farm-out, our participating interest in the Cap Boujdour Offshore block is 55.0% and we remain the operator. The Moroccan national oil company, 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 300,000 tons produced are exempt from royalty) and 7% royalty on oil produced in water depths deeper than 200 meters (the first 500,000 tons produced are exempt from royalty). These royalties are to be paid in-kind or, at the election of the government of Morocco, in cash. A corporate tax rate of 30% is applied to profits at the license level following a 10-year tax holiday post first production, 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 are obligated to drill one exploration well. To meet this obligation, we began drilling the CB-1 exploration well in December 2014. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 25 years

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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 non-operating interest in the Foum Assaka Offshore block. BP funded Kosmos' share of the cost of one 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% carried participating interest and is carried by the block partners proportionately during the exploration phase. We are required to pay a 10% royalty on oil produced in water depths of 200 meters or less (the first 300,000 tons produced are exempt from royalty) and 7% royalty on oil produced in water depths deeper than 200 meters (the first 500,000 tons produced are exempt from royalty). These royalties are to be paid in-kind or, at the election of the government of Morocco, in cash. A corporate tax rate of 30% is applied to profits at the license level following a 10-year tax holiday post first production. The term of the 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 are 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 and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        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. 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 30.0% in the Essaouria Offshore block and we remain the operator. The Moroccan national oil company, ONHYM, has a 25% carried participating interest and is carried by the block partners proportionately during the exploration phase. We are required to pay a 10% royalty on oil produced in water depths of 200 meters or less (the first 300,000 tons produced are exempt from royalty) and 7% royalty on oil produced in water depths deeper than 200 meters (the first 500,000 tons produced are exempt from royalty). These royalties are to be paid in-kind or, at the election of the government of Morocco, in cash. A corporate tax rate of 30% is applied to profits at the license level following a 10-year tax holiday post first production. The term of the Essaouria Offshore Permits, beginning November 8, 2011, is eight years and includes an initial exploration period of two years and six months followed by the first extension period of three years and

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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 and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

        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% carried 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 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 30.0% 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 300,000 tons produced are exempt from royalty) and 7% royalty on oil produced in water depths deeper than 200 meters (the first 500,000 tons produced are exempt from royalty). These royalties are to be paid in-kind or, at the election of the government of Morocco, in cash. A corporate tax rate of 30% is applied to profits at the license level following a 10-year tax holiday post first production. The 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 and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for an additional period of 10 years under certain circumstances.

Suriname Exploration Agreements

        On December 13, 2011, we signed a petroleum contract covering Offshore Block 42 located offshore Suriname. We have a 50% participating interest in the block and are the operator. Staatsolie Maatschappij Suriname N.V. ("Staatsolie"), Suriname's national oil company, has the option to back into the contract with an interest of not more than 10% upon approval of a development plan. In November 2012, Kosmos closed an agreement with Chevron under which Kosmos assigned half of its interest in Block 42, offshore Suriname, to Chevron. Each party 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 ends in December 2015. There are two renewal periods consisting of three years for the first renewal period and two years for the second renewal period. Each renewal period carries a one well drilling obligation. In the event of commercial success, the duration of the contract will be 30 years from the effective date or 25 years from governmental approval of a plan of development, whichever is longer. Block 42 comprises approximately 1.5 million acres (approximately 6,176 square kilometers).

        On December 13, 2011, we signed a petroleum contract covering Offshore Block 45 located offshore Suriname. We have a 50% participating interest in the block and are the operator. Staatsolie

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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 for up to nine months, or September 2015. 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, Société Mauritanienne des Hydrocarbures ("SMH") now called Société Mauritanienne des Hydrocarbures et de Patrimoine Minier ("SMHPM"), currently has a 10% carried participating interest during the exploration period only. Should a commercial discovery be made, SMHPM's 10% carried interest is extinguished and SMHPM will have an option to acquire a participating interest of 10% to 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 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. 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 February 2015, we entered into a farm-out agreement with Chevron Mauritania Exploration Limited, a wholly owned subsidiary of Chevron Corporation (Chevron), covering the C8, C12 and C13 petroleum contracts offshore Mauritania. Under the terms of the farm-out agreement, Chevron will acquire a 30% non-operated working interest in each of the contract areas. Chevron will pay a disproportionate share of the costs of one exploration well and a second contingent exploration well, subject to maximum expenditure caps. In addition, Chevron will pay its proportionate share of previously incurred exploration costs. Chevron will not initially fund drilling of the Tortue prospect, but retains the option to participate in this prospect after the transaction is completed. The transaction is subject to customary closing conditions, including approval by the Mauritania government. Once these farm-out agreements become effective, Kosmos, Chevron and SMHPM's participating interest in Block C8, Block C12 and Block C13 will be 60%, 30% and 10%, respectively.

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Ireland Exploration Agreements

        Effective April 17, 2013, we entered into three farm-in agreements, whereby we have an 85% participating interest in Frontier Exploration License 2/13 and 3/13, and a 75% participating interest in Frontier Exploration License 1/13, all part of the Porcupine Basin, offshore Ireland. We are the operator of the three blocks. We are required to pay a corporate income tax rate of 25% and potentially a petroleum resource rent tax of between 0% and 15% as determined by a profitability-based sliding scale. The term of each contract is 15 years unless surrendered or revoked, and is divided into an initial phase of three years, and three subsequent phases of four years each. The second phase work program must include an exploration well. The contract area must be surrendered if a second exploration well has not been commenced by the end of the third phase. Upon entering these Frontier Exploration Licenses, we and the other block partners relinquished approximately 25% of the acreage covered by the Licensing Options. In the event of commercial success, we have the right to develop and produce oil for a period of time as agreed with the Minister of Communications, Energy and Natural Resources from the grant of a Petroleum Lease from the government, which may be extended for an additional period as agreed with the Minister of Communications, Energy and Natural Resources under certain circumstances.

        In Frontier Exploration License 2/13 and 3/13, Europa has a 15% participating interest in the areas. In addition to fully funding a 3D seismic acquisition and processing, if we drill, we will also fund 100% of the costs of the first exploration well on each block, subject to an investment cap of $90.0 million on Frontier Exploration License 2/13 and $110.0 million on Frontier Exploration License 3/13.

        In Frontier Exploration License 1/13, Antrim has a 25% participating interest in the area. We fully funded a 3D seismic program on the block.

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. As part of the agreement, we will reimburse a portion of Repsol's previously incurred exploration costs, as well as partially carry Repsol's share of the costs of a planned 3D seismic program. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. After completing the acquisition, our participating interest in the blocks will be 31%.

        The contracts for the four blocks were awarded in May of 2007 and provided 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 2020, with drilling obligations in years four (June 2015 to June 2016), six (June 2017 to June 2018) and eight (June 2019 to June 2020). Drilling a well on any block serves to fulfill the requirement for all four blocks. We may relinquish the blocks at any time in the event we decide not to drill. We currently are in discussions with partners and the government regarding an extension to the current period to allow acquisition of a 3D seismic survey and further assessment of the prospectivity of the blocks.

Senegal Exploration Agreements

        In August 2014, we entered into a farm-in agreement with Timis Corporation Limited, whereby we acquired a 60% participating interest and operatorship, covering the Cayar Offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal. In September 2014, the Senegal government issued the requisite approvals for the farm-out agreement. As part of the agreement, we carried the full costs of a 3D seismic program which was completed in January 2015. Additionally, we will carry the full costs of one exploration well in each of the blocks, subject to a maximum gross cost per well of $120.0 million, should Kosmos elect to drill such wells. We also retain the option to increase our equity

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interest in each block to 65% in exchange for carrying the full cost of a third exploration or appraisal well, subject to a maximum gross cost of $120.0 million.

        The Cayar Offshore Profond and Saint Louis Offshore Profond blocks are currently in a one-year extension of the first exploration period of each petroleum contract, which now ends in June of 2015. Each exploration phase may be extended to December 2020 at our election subject to our fulfilling specific work obligations including an exploration well in the next exploration period of three years 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 and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for at least one additional period of 10 years under certain circumstances.

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 an agreement with an oil marketing agent to market our share of the Jubilee Field oil, and we approve the terms of each sale proposed by such agent. We do not anticipate entering into any long term sales agreements at this time.

        There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil, the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long-term material adverse effect on our financial position or results of operations.

Competition

        The oil and gas industry is competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring 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 restrict our ability to drill wells and conduct our operations.

        The oil and gas industry as a whole experienced a significant decline in crude oil prices during the second half of 2014. Dated Brent crude, the benchmark for our oil sales, peaked above $115 per barrel in June before falling below $60 per barrel at year-end. Excluding the impact of hedges, our December realized price was $62.00 per barrel. We believe lower prices will 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.

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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:

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require the acquisition of various permits before operations commence;

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enjoin some or all of the operations or facilities deemed not in compliance with permits;

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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;

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limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and

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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 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.

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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 auxillary 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 5,000 cubic meters of dispersant strategically located at OSRL bases around the world. The total volume of the stockpile located at the OSRL bases is approximate to the amount used in the Macondo spill response.

Ghana

        We have developed and adopted an Oil Spill Contingency Plan ("OSCP") for the coordination of responses to oil spills arising from our operations in Ghana, including the WCTP Block. In addition, Tullow 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. More than 200 personnel (composed primarily of Tullow and Kosmos employees, Ghanaian Navy, Ghana EPA, Maritime Authority, Petroleum Commission, Ports and Harbor personnel, local contractors and community representatives) have been trained on the assembly and operation of Tier 1 and Tier 2 onshore, nearshore and harbor response equipment. In the case of a Tier 3 incident, we would engage the services of OSRL.

        Our associate membership with OSRL entitles us to utilize its oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. Kosmos does not own any oil spill response equipment. Instead, Kosmos and Tullow each maintain separate 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.

        As Unit Operator for the Jubilee Field, 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 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.

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        In the case of a Tier 3 event, our associate membership in OSRL provides us with access to the large stockpile of equipment in Southampton, United Kingdom along with access to additional dispersant spraying aircraft. Kosmos could hire additional resources such as boats, earth moving equipment and personnel as necessary to respond to such an event. While we have the above 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) and Mauritania

        We have an Oil Spill Contingency Plan to support our drilling operations. The plan calls for the addition of Tier 1 spill equipment to our shorebase in Agadir, Morocco to respond to a harbor or shoreline incident in the area. 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 used 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 contractor's 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 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. Ghana's Ministry of Energy represents the state in its executive capacity. The Petroleum Commission is the regulatory body for the upstream petroleum industry and the advisor to the Ministry of Energy. GNPC has rights to undertake petroleum operations in any acreage declared open by Ghana's Ministry of Energy. As well, when petroleum operations are undertaken by GNPC in association with contracts, 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

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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 Exploration and Production Act and our Ghanaian petroleum agreements contain provisions restricting the direct or indirect assignment or transfer of such petroleum agreements or interests thereunder without the prior written consent of GNPC and the Ministry of Energy. The Petroleum Exploration and Production Act also imposes certain restrictions on the direct or indirect transfer by a contractor of shares of its incorporated company in Ghana to a third party without the prior written consent of Ghana's Minister of Energy. The Ghanaian Tax Law may impose certain taxes upon the direct or indirect transfer of interests in the petroleum agreements or interests thereunder.

        Ghana's Parliament is considering the enactment of a new Petroleum Exploration and Production Act and has enacted a new Petroleum Revenue Management Act and the Petroleum Commission Act of 2011. The new 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 creates the Petroleum Commission, whose objective is to regulate and manage the use of petroleum resources and coordinate the policies thereto. The Petroleum Commission became effective in January 2012. Among the Petroleum Commission's functions are advising the Minister of Energy on matters such as appraisal plans, field development plans, recommending to the Minister national policies related to petroleum, and storing and managing data. We understand the primary purpose of the Petroleum Commission is to fulfill the regulatory functions previously undertaken by GNPC. We currently believe that such laws will only have prospective application, and as such will not modify the terms of (or interests under) the agreements governing our license interests in Ghana, including the WCTP and DT petroleum contracts (which include stabilization clauses) and the UUOA, and will not impose additional restrictions on the direct or indirect transfer of our license interests, including upon a change of control. The Petroleum (Local Content and Local Participation in Petroleum Activities) Regulations came into effect in February 2014. The Regulations mandate certain levels of local participation in service companies, in-country manufacturing of goods and the provision of services, and certain reporting requirements.

Ireland

        The primary legislative acts relevant to our operations in the Republic of Ireland are: (1) The Petroleum and Other Minerals Development Act, 1960 (the "Irish Petroleum Act") and (2) the Gas Act, 1960. The Ministry of Communications, Energy and Natural Resources is the regulatory authority tasked with maximizing the benefits to the Irish State from exploration for and production of indigenous oil and gas resources. The Irish Petroleum Act vests all State petroleum in the Minister. Only the Minister, licensees under an exploration license, a petroleum prospecting license, or a reserved area license, and lessees under a valid petroleum lease may search for petroleum. The Ministry enters into petroleum agreements (licenses for exploration and leases for development and production) on behalf of the State. Assignments of interests in licenses also require the consent of The Ministry. The relevant tax law is the Taxes Consolidation Act, 1997, as amended by the Finance Act, 1999. The current license and lease terms are found in the Licensing Terms for Offshore Oil and Gas Exploration, Development & Production, 2007.

Mauritania

        The main legislative acts in the Islamic Republic of Mauritania relevant to petroleum exploration and production are Law No. 2010-033 dated July 20, 2010 and its amendment (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

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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 exploration-production 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% in the rights of the contractor during the exploitation period.

Morocco (including Western Sahara)

        The two main legislative acts in Morocco relevant to petroleum exploration and production are (i) the Law 21-90 (April 1, 1992) as amended and completed by the Law 27-99 (February 15, 2000) and (ii) the Decree 2-93-786 (November 3, 1993) as amended and completed by decree 2-99-210 (March 16, 2000) (together, "Morocco's Petroleum Laws"). The regulatory authority in Morocco is the Ministry of Energy, Mines, Water and Environment and the national oil company acting on its behalf is ONHYM. ONHYM is a public establishment ( établissement public ) with the legal personality and financial autonomy created pursuant to the Law 33-01 (November 11, 2003) which was further completed by the Decree 2-04-372 (December 29, 2004).

        Pursuant to the Law 21-90, the granting of an exploration permit is subject to the conclusion of a petroleum contract with the Moroccan State. Therefore, companies who wish to gain rights to explore and produce in Morocco can only do so by entering into a petroleum contract with ONHYM acting on behalf of the State. It is further provided that the State of Morocco (via ONHYM) shall retain a participation in exploration permits or exploitation concessions which shall not be in excess of 25%. More generally, ONHYM is representing the State of Morocco for licensing, exploration and exploitation matters within the limit of its prerogatives set out pursuant to the Law 33-01. Assignments of interests in exploration permits also require the consent of the administration pursuant to the Law 21-90.

        The Sahrawai 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.

Portugal

        The primary legislative acts in Portugal relevant to petroleum exploration and production are Decree-Law 109/94, of April 16, 1994—governing petroleum exploration and production activities (the "Petroleum Law")—and Order 790/94, of September 5, 1994—concerning 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 a grey area between DGEG's and ENMC's powers and authority in respect of the upstream oil sector. DGEG's authority derives from Decree-Law 130/2014, of August 29, 2014—which approves DGEG's organic statute—and ENMC's from Decree-Law 165/2013, of December 16, 2013—which 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 concessionaire's share capital) requires the consent of the Minister.

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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) Staatsolie's Concession Agreement (Decree E8-B, Official Gazette 1981 no. 59), (ii) the Mining Decree of 1986 (Official Gazette 1986 no. 28) and (iii) the Petroleum Law 1990 (Official Gazette 1991 no. 7, as amended in 2001).

        The Mining Decree granted concession rights for petroleum activities to state enterprises. Staatsolie was founded in 1980 as a state enterprise and holds mining rights onshore and offshore in Suriname. The Suriname Petroleum Law granted state enterprises with petroleum concession rights the authority, upon the approval of the Minister of Natural Resources, to enter into petroleum contracts with E&P companies. Therefore, companies who wish to gain rights to explore and produce in Suriname can only do so by entering into a petroleum contract with Staatsolie, subject to approval by the Minister of Natural Resources. Assignments of interests in petroleum contracts also require the consent of Staatsolie and/or The Minister of Natural Resources.

Certain Bermuda Law Considerations

        As a Bermuda exempted company, we are subject to regulation in Bermuda. Among other things, we must comply with the provisions of the Bermuda Companies Act regulating the payment of dividends and making of distributions from contributed surplus.

        We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares.

        Under Bermuda law, "exempted" companies are companies formed for the purpose of conducting business outside Bermuda from a principal place of business in Bermuda. As an exempted company, we may not, without a license or consent granted by the Minister of Finance, participate in certain business transactions, including transactions involving Bermuda landholding rights and the carrying on of business of any kind for which we are not licensed in Bermuda.

Employees

        As of December 31, 2014, we had approximately 230 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.

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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 NYSE and our common shares are traded under the symbol KOS. We file or furnish annual, quarterly and current reports, proxy statements and other information with the SEC. The public may read and copy any reports, statements or other information at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information about the operation of the public reference room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a website at http://www.sec.gov that contains documents we file electronically with the SEC.

        The Company also maintains an internet website under the namewww.kosmosenergy.com. The information on our website is not incorporated by reference into this annual report on Form 10-K and should not be considered a part of this annual report on Form 10-K. Our website is included as an inactive technical reference only. We make available, free of charge, on our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC.

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Item 1A.    Risk Factors

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

We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.

        We have limited proved reserves. A portion of our oil and natural gas assets consists of discoveries without approved PoDs and with limited well penetrations, as well as identified yet unproven prospects based on available seismic and geological information that indicates the potential presence of hydrocarbons. However, the areas we decide to drill may not yield oil or natural gas in commercial quantities or quality, or at all. Many of our current discoveries and all of our prospects are in various stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. Accordingly, we do not know if any of our discoveries or prospects will contain oil or natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil or natural gas is found on our discoveries or prospects in commercial quantities, construction costs of gathering lines, subsea infrastructure and floating production systems and transportation costs may prevent such discoveries or prospects from being economically viable, and approval of PoDs by various regulatory authorities, a necessary step in order to designate a discovery as "commercial," 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 potentially 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, Senegal, Suriname, Mauritania and Ireland licenses have not yet proved to be economically viable production areas, as to date we do not have a commercially viable discovery or production in these regions. 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

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been drilled. Any analogies drawn by us from other wells, discoveries or producing fields may not prove to be accurate indicators of the success of developing proved reserves from our discoveries and prospects. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or prospects produced by other parties which we may use.

        It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quality or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of hydrocarbons attributable to any particular prospect.

Drilling wells is speculative, often involving significant costs that may be more than we estimate, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

        Exploring for and developing hydrocarbon reserves involves a high degree of 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 can not 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, 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 a number of 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.

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        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 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;

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•
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 on a per share basis 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, 2014, we have unfulfilled drilling obligations in our Cap Boujdour and Essaouria petroleum contracts. In our other petroleum contracts, we are in the first 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 second 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 phase 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, we cannot assure you that we will determine to enter any such new petroleum contracts. For each of our petroleum contracts, we cannot assure you that any renewals or extensions will be granted or whether any new agreements will be available on commercially reasonable terms, or, in some cases, at all. For additional detail regarding the status of our operations with respect to our various petroleum contracts, please see "Item 1. Business—Operations by Geographic Area."

The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results.

        We may be liable for certain costs if third parties who contract with us are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or unit partners. If any of our partners in the blocks or unit in which we hold interests are unable to fund their share of the exploration and development expenses, we may be liable for such costs. In the past, certain of our WCTP and DT Block partners have not paid their share of block costs in the time frame required by the joint operating agreements for these blocks. This has resulted in such party being in default, which in return requires Kosmos and its non-defaulting

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block partners to pay their proportionate share of the defaulting party's costs during the default period. Should a default not be cured, Kosmos could be required to pay its share of the defaulting party's costs going forward.

        In addition, we contract with third parties to conduct drilling and related services on our development projects and exploration prospects. Such third parties may not perform the services they provide us on schedule or within budget. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by the third parties we contract with is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial position and results of operations.

        Our principal exposure to credit risk will be through receivables resulting from the sale of our oil, which we plan to market to energy marketing companies and refineries, 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% (our percentage after Tullow's acquisition of a block partner's interest in July 2011) to 24.1%. An additional redetermination could occur sometime if requested by a party that holds greater than a 10% interest in the 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

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terms of our other current or future license or venture agreements may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability to exercise influence over the operations of the discoveries or prospects operated by our block or unit partners, or which are not wholly owned by us, as the case may be. Dependence on block or unit partners could prevent us from realizing our target returns for those discoveries or prospects. Further, because we do not have majority ownership in all of our properties, we may not be able to control the timing, or the scope, of exploration or development activities or the amount of capital expenditures and, therefore, may not be able to carry out one of our key business strategies of minimizing the cycle time between discovery and initial production. The success and timing of exploration and development activities operated by our block partners will depend on a number of factors that will be largely outside of our control, including:

•
the timing and amount of capital expenditures;

•
the operator's expertise and financial resources;

•
approval of other block partners in drilling wells;

•
the scheduling, pre-design, planning, design and approvals of activities and processes;

•
selection of technology; and

•
the rate of production of reserves, if any.

        This limited ability to exercise control over the operations on some of our license areas may cause a material adverse effect on our financial condition and results of operations.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

        The process of estimating oil and natural gas reserves is technically complex. It requires interpretations of available technical data and many assumptions, including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report. See "Item 1. Business—Our Reserves" for information about our estimated oil and natural gas reserves and the present value of our net revenues at a 10% discount rate ("PV-10") and Standardized Measure of discounted future net revenues (as defined herein) as of December 31, 2014.

        In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

        Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

        You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with the SEC requirements, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months, adjusted for 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, 2014 would each decrease by approximately $50.4 million. Oil prices have recently experienced significant declines. See "Item 1. Business—Our Reserves."

We are dependent on certain members of our management and technical team.

        Our performance and success largely depend on the ability, expertise, judgment and discretion of our management and the ability of our technical team to identify, discover, evaluate and develop reserves. The loss or departure of one or more members of our management and technical team could be detrimental to our future success. Additionally, a significant amount of shares in Kosmos held by members of our management and technical team have 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 effected. 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

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additional debt financing, strategic alliances or future private or public equity offerings if our cash flows from operations, or the timing of, are not sufficient to cover such costs.

        Our future capital requirements will depend on many factors, including:

•
the scope, rate of progress and cost of our exploration, appraisal, development and production activities;

•
the success of our exploration, appraisal, development and production activities;

•
oil and natural gas prices;

•
our ability to locate and acquire hydrocarbon reserves;

•
our ability to produce oil or natural gas from those reserves;

•
the terms and timing of any drilling and other production-related arrangements that we may enter into;

•
the cost and timing of governmental approvals and/or concessions; and

•
the effects of competition by larger companies operating in the oil and gas industry.

        We do not currently have any commitments for future external funding beyond the capacity of our commercial debt facility and revolving credit facility. Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our licenses, we would dilute our ownership interest subject to the farm-out and any potential value resulting therefrom, and may lose operating control or influence over such license areas.

        Assuming we are able to commence exploration, appraisal, development and production activities or successfully exploit our licenses during the exploratory term, our interests in our licenses (or the development/production area of such licenses as they existed at that time, as applicable) could extend beyond the term set for the exploratory phase of the license to a fixed period or life of production, depending on the jurisdiction. If we are unable to meet our well commitments and/or declare commerciality of the prospective areas of our licenses during this time, we may be subject to significant potential forfeiture of all or part of the relevant license interests. If we are not successful in raising additional capital, we may be unable to continue our exploration and production activities or successfully exploit our license areas, and we may lose the rights to develop these areas. See "—Under the terms of our various license agreements, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to declare any discoveries and thereby establish development areas may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects."

        All of our proved reserves, oil production and cash flows from operations are currently associated with our licenses offshore Ghana. Should any event occur which adversely affects such proved reserves, oil production and cash flows from these licenses, including, without limitation, any event resulting from the risks and uncertainties outlined in 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.

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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. 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 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

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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 2015 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, 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.

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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;

•
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.

        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.

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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 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.

        All of our proved reserves and our discovered fields 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 and/or Ghana's Ministry of Energy. We have previously had disagreements with the Ministry of Energy and GNPC regarding certain of our rights and responsibilities under these petroleum contracts, the Petroleum Law of 1984 (PNDCL 84) (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 in connection with our initial public offering, 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 and/or the government of Ghana.

        There can be no assurance that future disagreements will not arise with any host government and/or national oil companies that may have a material adverse effect on our exploration or development activities, our ability to operate, our rights under our licenses and local laws or our rights to monetize our interests.

The geographic locations of our licenses in Africa, 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; and/or

•
international border disputes.

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        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

•
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,

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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 Sahrawai Arab Democratic Republic.

        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 territory's sovereignty has been in dispute since 1975. The Polisario Front, representing the SADR, has a conflicting claim of sovereignty over Western Sahara. No countries have formally recognized Morocco's claim to Western Sahara, although some countries implicitly support Morocco's position. Other countries have formally recognized the SADR, but the UN has not. A UN-administered cease-fire has been in place since 1991, and while there have been intermittent UN-sponsored talks, between Morocco and SADR (represented by the Polisario), the dispute remains stalemated. It is uncertain when and how Western Sahara's 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 SADR's conflicting claim of rights to oil and natural gas licenses granted by Morocco, and the SADR's claims that Morocco's exploitation of Western Sahara's natural resources violates international law, our interests could decrease in value or be lost. Any political instability, terrorism, changes in government, or escalation in hostilities involving the SADR, Morocco or neighboring states could adversely affect our operations and assets. In addition, Morocco has recently experienced political and social disturbances that could affect its legal and administrative institutions. A change in U.S. foreign policy or the policies of other countries regarding Western Sahara could also adversely affect our operations and assets. We are not insured against political or terrorism risks because management deems the premium costs of such insurance to be currently prohibitively expensive relative to the limited coverage provided thereby.

        Furthermore, various activist groups have mounted public relations campaigns to force companies to cease and divest operations in Western Sahara, and we could come under similar public pressure. Some investors have refused to invest in companies with operations in Western Sahara, and we could be subject to similar pressure. Any of these factors could have a material adverse effect on our results of operations and financial condition.

Maritime boundary demarcation between Côte D'Ivoire and Ghana may affect a portion of our license areas.

        In early 2010, Ghana's western neighbor, the Republic of Côte d'Ivoire, petitioned the United Nations to demarcate the Ivorian territorial maritime boundary with Ghana. In response to the petition, Ghana established a Boundary Commission to undertake negotiations with Côte d'Ivoire in order to agree to Ghana's land and maritime boundaries. In September 2014, Ghana submitted the dispute to arbitration under the United Nations Convention on the Law of the Sea but in December 2014, the two parties agreed to transfer the dispute to the International Tribunal for the Law of the Sea (the "ITLOS"). On January 12, 2015, the ITLOS formed a special chamber to address the maritime boundary dispute. The issue remains unresolved at present.

        The Ghanaian-Ivorian maritime boundary forms the western boundary of the DT Block offshore Ghana. In September 2011, the Ivorian Government issued a map reflecting potential petroleum license areas that overlap with the DT Block. Uncertainty remains with regard to the outcome of the boundary

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demarcation between Ghana and Côte d'Ivoire and we do not know if the maritime boundary will change, therefore affecting our rights to develop our discoveries within such areas. In the event that Côte d'Ivoire is successful in its maritime border claims or if the proceedings result in an unfavorable outcome for Ghana, our operations within such areas could be materially impacted.

The oil and gas industry, including the acquisition of exploratory licenses, is intensely competitive and many of our competitors possess and employ substantially greater resources than us.

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

Participants in the oil and gas industry are subject to numerous laws that can affect the cost, manner or feasibility of doing business.

        Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be required to make large expenditures to comply with governmental laws and regulations, particularly in respect of the following matters:

•
licenses for drilling operations;

•
tax increases, including retroactive claims;

•
unitization of oil accumulations;

•
local content requirements (including the mandatory use of local partners and vendors); and

•
environmental requirements and obligations, including those related to remediation, investigation or permitting.

        Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change, or their interpretations could change, in ways that could substantially increase our costs. These risks may be higher in the developing countries in which we conduct a majority of our operations, where there could be a lack of clarity or lack of consistency in the application of these laws and regulations. Any resulting liabilities, penalties, suspensions or terminations could have a material adverse effect on our financial condition and results of operations.

        For example, Ghana's Parliament has enacted the Petroleum Revenue Management Act and 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

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petroleum contracts and the UUOA, require governmental approval for transactions that effect a direct or indirect change of control of our license interests or otherwise affect our current and future operations in Ghana. Any such changes may have a material adverse effect on our business. We also cannot assure you that government approval will not be needed for direct or indirect transfers of our petroleum agreements or interests thereunder based on existing legislation. See "Item 1. Business—Other Regulation of the Oil and Gas Industry—Ghana."

        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 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 and the SEC has not as yet proposed revised rules implementing the applicable section of the Dodd-Frank Act. 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.

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        We are not fully insured against all risks and our insurance may not cover any or all environmental, health or safety claims that might arise from our operations or at any of our license areas. If a significant accident or other event occurs and is not covered by insurance, such accident or event could have a material adverse effect on our results of operations and financial condition.

        Releases of regulated substances may occur and can be significant. Under certain environmental laws, we could be held responsible for all of the costs relating to any contamination at our current or former facilities and at any third party waste disposal sites used by us or on our behalf. In addition, offshore oil and natural gas exploration and production involves various hazards, including human exposure to regulated substances, which include naturally occurring radioactive, and other materials. As such, we could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of any regulated or otherwise hazardous substances to the environment, property or to natural resources, or affecting endangered species.

        In addition, we expect continued and increasing attention to climate change issues. Various countries and regions, including Ghana, Ireland, Mauritania, Morocco (including Western Sahara), Senegal and Suriname, are partners to the Kyoto Protocol, an international treaty aimed at reducing emissions of greenhouse gases ("GHGs"), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). While the Kyoto Protocol was set to expire in 2012, it has been extended by amendment until 2020 with the understanding among the parties that a new climate change regime will be negotiated in December 2015 and implemented by 2020. Ireland is also a party to the European Union Emissions Trading System, a "cap and trade" GHG emissions framework. The increased regulation of GHGs by any of the areas in which we, our customers and the end-users of our products currently or in the future operate may increase our compliance costs, such as for monitoring, sequestering, purchasing emissions allowances or reducing emissions and may have an adverse impact on the global supply and demand for oil and natural gas, which could have a material adverse impact on our business or results of operations. The physical impacts of climate change in the areas in which our assets are located or in which we otherwise operate, including through increased severity and frequency of storms, floods and other weather events, could adversely impact our operations or disrupt transportation or other process-related services provided by our third-party contractors.

        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;

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•
restrictions on installation or operation of gathering or processing facilities;

•
restrictions on the use of certain operating practices;

•
legal challenges or lawsuits;

•
damaging publicity about us;

•
increased regulation;

•
increased costs of doing business;

•
reduction in demand for our products; and

•
other adverse effects on our ability to develop our properties.

        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 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.

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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. For example, we are not insured against political or terrorism risks. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations.

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 litigations and any loss exceeds our available insurance, this could have a material adverse effect on our results of operations.

        Because we maintain a diversified portfolio of assets overseas, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability and/or negative publicity about us and adversely affect the price of our common shares. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

We face various risks associated with global populism.

        Globally, certain individuals and organizations are attempting to focus public attention on income distribution, wealth distribution, and corporate taxation levels, and implement income and wealth redistribution policies. These efforts, if they gain political traction, could result in increased taxation on individuals and/or corporations, as well as, potentially, increased regulation on companies and financial institutions. Our need to incur costs associated with responding to these developments or complying with any resulting new legal or regulatory requirements, as well as any potential increased tax expense, could increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our business, financial condition and results of our operations.

Slower global economic growth rates may materially adversely impact our operating results and financial position.

        The recovery from the global economic crisis of 2008 and resulting recession has been slow and uneven. Market volatility and reduced consumer demand have increased economic uncertainty, and the current global economic growth rate is slower than what was experienced in the decade preceding the crisis. Many developed countries are constrained by long term structural government budget deficits and international financial markets and credit rating agencies are pressing for budgetary reform and discipline. This need for fiscal discipline is balanced by calls for continuing government stimulus and social spending as a result of the impacts of the global economic crisis. As major countries implement government fiscal reform, such measures, if they are undertaken too rapidly, could further undermine economic recovery, reducing demand and slowing growth. Impacts of the crisis could spread to China

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and other emerging markets, which have fueled global economic development in recent years, slowing their growth rates, reducing demand, and resulting in further drag on the global economy.

        Global economic growth drives demand for energy from all sources, including hydrocarbons. A lower future economic growth rate is likely to result in decreased demand growth for our crude oil and natural gas production. A decrease in demand, notwithstanding impacts from other factors, could potentially result in lower commodity prices, which would reduce our cash flows from operations, our profitability and our liquidity and financial position.

Increased costs of capital could adversely affect our business.

        Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Our derivative activities could result in financial losses or could reduce our income.

        To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have and may in the future enter into derivative arrangements for a portion of our oil and natural gas production, including, but not limited to, puts, collars and fixed-price swaps. In addition, we currently, and may in the future, hold swaps designed to hedge our interest rate risk. We do not currently designate any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

        Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

•
production is less than the volume covered by the derivative instruments;

•
the counter-party to the derivative instrument defaults on its contract obligations; or

•
there is an increase in the differential between the underlying price and actual prices received in the derivative instrument.

        In addition, these types of derivative arrangements may limit the benefit we could receive from increases in the prices for oil and natural gas or beneficial interest rate fluctuations and may expose us to cash margin requirements.

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;

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•
our incurrence of additional indebtedness;

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the granting of liens, other than liens created pursuant to the commercial debt facility, revolving credit facility or the indenture governing the Senior Notes and certain permitted liens;

•
mergers, consolidations and sales of all or a substantial part of our business or licenses;

•
the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;

•
the sale of assets (other than production sold in the ordinary course of business); and

•
in the case of the commercial debt facility and the revolving credit facility, our capital expenditures that we can fund with the proceeds of our commercial debt facility, and revolving credit facility.

        Our commercial debt facility, revolving credit facility and letter of credit facility require us to maintain certain financial ratios, such as debt service coverage ratios and cash flow coverage ratios. All of these restrictive covenants may limit our ability to expand or pursue our business strategies. Our ability to comply with these and other provisions of our commercial debt facility, revolving credit facility and indenture governing the Senior Notes may be impacted by changes in economic or business conditions, our results of operations or events beyond our control. The breach of any of these covenants could result in a default under our commercial debt facility, revolving credit facility and indenture governing the Senior Notes, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under our commercial debt facility, revolving credit facility and indenture governing the Senior Notes, together with accrued interest, to be due and payable and, in the case of the letter of credit facility, the breach of any of the applicable covenants could result in a default, in which case the cash collateral we are required to maintain under the letter of credit facility would increase from 75% to 100% of all outstanding letters of credit, and if such additional cash is not posted, the lenders thereunder could elect to declare all amounts outstanding thereunder, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders, successors or assignees could proceed against their collateral. If the indebtedness under our commercial debt facility, revolving credit facility, letter of credit facility and indenture governing the Senior Notes were to be accelerated, our assets may not be sufficient to repay in full such indebtedness. In addition, the limitations imposed by the commercial debt facility, the revolving credit facility, the letter of credit facility and the indenture governing the Senior Notes on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing.

Provisions of our Senior Notes could discourage an acquisition of us by a third party.

        Certain provisions of the indenture governing the Senior Notes could make it more difficult or more expensive for a third party to acquire us, or may even prevent a third party from acquiring us. For example, upon the occurrence of a "change of control triggering event" (as defined in the indenture governing the Senior Notes), holders of the notes will have the right, at their option, to require us to repurchase all of their notes or any portion of the principal amount of such notes. By discouraging an acquisition of us by a third party, these provisions could have the effect of depriving the holders of our common shares of an opportunity to sell their common shares at a premium over prevailing market prices.

Our level of indebtedness may increase and thereby reduce our financial flexibility.

        At December 31, 2014, we had $500.0 million outstanding and $1.0 billion of committed undrawn capacity under our commercial debt facility, subject to borrowing base availability. As of December 31, 2014, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability

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was $300.0 million. As of December 31, 2014, there were seven outstanding letters of credit totaling $21.5 million under the letter of credit facility agreement and $300.0 million principal amount of Senior Notes outstanding. We also currently have, and may in the future incur, significant off balance sheet obligations. In the future, we may incur significant indebtedness in order to make investments or acquisitions or to explore, appraise or develop our oil and natural gas assets.

        Our level of indebtedness could affect our operations in several ways, including the following:

•
a significant portion or all of our cash flows, when generated, could be used to service our indebtedness;

•
a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions;

•
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

•
a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing;

•
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

•
additional hedging instruments may be required as a result of our indebtedness;

•
a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

•
a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

        A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, risks associated with exploring for and producing oil and natural gas, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our indebtedness and future working capital, borrowings or equity financing may not be available to pay or refinance such indebtedness. Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital.

We are a holding company and our ability to make payments on our outstanding indebtedness, including our Senior Notes and our commercial debt facility, is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise.

        We are a holding company, and our subsidiaries own all of our assets and conduct all of our operations. Accordingly, our ability to make payments of interest and principal on the Senior Notes and commercial debt facility will be dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors, our subsidiaries will not have any obligation to pay amounts due on the notes or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of the Senior Notes or the commercial debt facility. Each subsidiary is a distinct legal entity and, under certain circumstances, legal and

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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 Holdings) to provide cash to us through dividend, debt repayment or intercompany lending. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the Senior Notes and commercial debt facility.

We may be subject to risks in connection with acquisitions and the integration of significant acquisitions may be difficult.

        We periodically evaluate acquisitions of prospects and licenses, reserves and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of these assets or businesses requires an assessment of several factors, including:

•
recoverable reserves;

•
future oil and natural gas prices and their appropriate differentials;

•
development and operating costs; and

•
potential environmental and other liabilities.

        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject assets that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the assets to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We may not be entitled to contractual indemnification for environmental liabilities and could acquire assets on an "as is" basis. Significant acquisitions and other strategic transactions may involve other risks, including:

•
diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

•
the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

•
difficulty associated with coordinating geographically separate organizations; and

•
the challenge of attracting and retaining personnel associated with acquired operations.

        The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

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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 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

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treat a foreign corporation as a U.S. corporation for U.S. federal income tax purposes if substantially all of its senior management is located in the United States. If this or similar legislation is passed that changes our U.S. tax position, it could have a material adverse effect on our net income, our cash flow and our financial condition.

We may become subject to taxes in Bermuda after March 31, 2035, which may have a material adverse effect on our results of operations.

        The Bermuda Minister of Finance, under the Exempted Undertakings Tax Protection Act 1966 of Bermuda, as amended, has given us an assurance that if any legislation is enacted in Bermuda that would impose tax computed on profits or income, or computed on any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance tax, then the imposition of any such tax will not be applicable to us or any of our operations, shares, debentures or other obligations until March 31, 2035, except insofar as such tax applies to persons who ordinarily reside in Bermuda or to any taxes payable by us in respect of real property owned or leased by us in Bermuda.

The impact of Bermuda's letter of commitment to the Organization for Economic Cooperation and Development to eliminate harmful tax practices is uncertain and could adversely affect our tax status in Bermuda.

        The Organization for Economic Cooperation and Development ("OECD") has published reports and launched a global initiative among member and non- member countries on measures to limit harmful tax competition. These measures are largely directed at counteracting the effects of tax havens and preferential tax regimes in countries around the world. According to the OECD, Bermuda is a jurisdiction that has substantially implemented the internationally agreed tax standard and as such is listed on the OECD "white" list. However, we are not able to predict whether any changes will be made to this classification or whether such changes will subject us to additional taxes.

The adoption of financial reform legislation by the United States Congress in 2010, and its implementing regulations, could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.

        We use derivative instruments to manage our commodity price and interest rate risk. The United States Congress adopted comprehensive financial reform legislation in 2010 that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as ours, that participate in that market. The Dodd-Frank Act was signed into law by the President on July 21, 2010. Many of the provisions of the Dodd-Frank Act require implementing regulations by agencies including the Commodity Futures Trading Commission (the "CFTC") and the SEC. The adopting and implementation of these regulations is underway but has not yet been completed, and it is not possible at this time to predict when this will be accomplished.

        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 adopted final position limit rules for 28 physical commodity contracts and related futures, options on futures and swaps on November 18, 2011, but these rules were vacated by the United States District Court for Columbia on September 28, 2012 after a lawsuit was brought by market participants. In November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain 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.

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        The CFTC has designated certain interest-rate 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.

        The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities. Rules that require end-users to post initial or variation margin could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to enter into derivatives to reduce risk and protect cash flows. While there are likely to be exceptions from many of these requirements for commercial end users of derivatives like us, the final contours of many of these exceptions, and whether we choose to use them, is uncertain at this time.

        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 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, and/or financial loss.

        The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data.

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        We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, co-venturers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, such as deepwater, and global competition for oil and gas resources make certain information more attractive to thieves.

        As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. For example, in 2012, a wave of network attacks impacted Saudi Arabia's oil industry and breached financial institutions in the U.S. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies.

        Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks, there can be no assurance that we will not be the target of cyber-attacks in the future or suffer such losses related to any cyber-incident. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Outbreaks of disease in the geographies in which we operate may adversely affect our business operations and financial condition.

        Many of our operations are currently, and will likely remain in the near future, in developing countries which are susceptible to outbreaks of disease and may lack the resources to effectively contain such an outbreak quickly. Such outbreaks may impact our ability to explore for oil and gas, develop or produce our license areas by limiting access to qualified personnel, increasing costs associated with ensuring the safety and health of our personnel, restricting transportation of personnel, equipment, supplies and oil and gas production to and from our areas of operation and diverting the time, attention and resources of government agencies which are necessary to conduct our operations. In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies.

        An epidemic of the Ebola virus disease is currently ongoing in parts of West Africa. A substantial number of deaths have been reported by the World Health Organization ("WHO") in West Africa, and the WHO has declared it a global health emergency. It is impossible to predict the effect and potential spread of the Ebola virus in West Africa and surrounding areas. Should the Ebola virus continue to spread, 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

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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 and/or terminated. The FPSO is potentially able to operate for a short period of time without access to the mainland, but if restrictions extended for a longer period we and the operator of the Jubilee Field would likely be required to cease production and other operations until such restrictions were lifted.
Risks Relating to Our Common Shares

Our share price may be volatile, and purchasers of our common shares could incur substantial losses.

        Our share price may be volatile. The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. The market price for our common shares may be influenced by many factors, including, but not limited to:

•
the price of oil and natural gas;

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

•
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

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can be freely sold in the public market upon issuance, unless pursuant to their terms these share awards have transfer restrictions attached to them. Sales of a substantial number of our common shares, or the perception in the market that the holders of a large number of shares intend to sell common shares, could reduce the market price of our common shares.

The concentration of our share capital ownership among our largest shareholders, and their affiliates, will limit your ability to influence corporate matters.

        Our two largest shareholders collectively own approximately 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 committee's purpose and responsibilities;

•
the compensation committee be composed entirely of independent directors with a written charter addressing the committee's 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.

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We do not intend to pay dividends on our common shares and, consequently, your only opportunity to achieve a return on your investment is if the price of our shares appreciates.

        We do not plan to declare dividends on shares of our common shares in the foreseeable future. Additionally, certain of our subsidiaries are currently restricted in their ability to pay dividends to us pursuant to the terms of our commercial debt facility unless they meet certain conditions, financial and otherwise. Consequently, investors must rely on sales of their common shares after price appreciation, which may never occur, as the only way to realize a return on their investment.

We are a Bermuda company and a significant portion of our assets are located outside the United States. As a result, it may be difficult for shareholders to enforce civil liability provisions of the federal or state securities laws of the United States.

        We are a Bermuda exempted company. As a result, the rights of holders of our common shares will be governed by Bermuda law and our memorandum of association and bye-laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. Some of our directors are not residents of the United States, and a substantial portion of our assets are located outside the United States. As a result, it may be difficult for investors to effect service of process on that person in the United States or to enforce in the United States judgments obtained in U.S. courts against us or that person based on the civil liability provisions of the U.S. securities laws. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions, including the United States, against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions.

Bermuda law differs from the laws in effect in the United States and might afford less protection to shareholders.

        Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company, we are governed by the Companies Act 1981 of Bermuda (the "Bermuda Companies Act"). The Bermuda Companies Act differs in some material respects from laws generally applicable to U.S. corporations and shareholders, including the provisions relating to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification of directors. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye-laws, which differ in certain respects from provisions of Delaware corporate law. Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders.

        Interested Directors.    Under Bermuda law and our bye-laws, as long as a director discloses a direct or indirect interest in any contract or arrangement with us as required by law, such director is entitled to vote in respect of any such contract or arrangement in which he or she is interested, unless disqualified from doing so by the chairman of the meeting, and such a contract or arrangement will not be voidable solely as a result of the interested director's participation in its approval. In addition, the director will not be liable to us for any profit realized from the transaction. In contrast, under Delaware law, such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each case if the material facts as to the interested director's relationship or interests are disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit.

        Mergers and Similar Arrangements.    The amalgamation of a Bermuda company with another company or corporation (other than certain affiliated companies) requires the amalgamation agreement

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to be approved by the company's board of directors and by its shareholders. Unless the company's bye-laws provide otherwise, the approval of 75% of the shareholders voting at such meeting is required to approve the amalgamation agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation (other than with a wholly owned subsidiary, per the Bermuda Companies Act) that has been approved by the board must only be approved by shareholders owning a majority of the issued and outstanding shares entitled to vote. Under Bermuda law, in the event of an amalgamation of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who is not satisfied that fair value has been offered for such shareholder's shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares. Under Delaware law, with certain exceptions, a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction.

        Shareholders' Suit.    Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company's memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company's shareholders than that which actually approved it.

        When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company's affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company.

        Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, except in respect of any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of 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.

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Item 1B.    Unresolved Staff Comments

        Not applicable.

Item 2.    Properties

        See "Item 1. Business." We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Note 15 of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for the future minimum rental payments. Such information is incorporated herein by reference.

Item 3.    Legal Proceedings

        From time to time, we may be involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the occurrence or outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows; however, an unfavorable outcome could have a material adverse effect on our results of operations for a specific interim period or year.

Item 4.    Mine Safety Disclosures

        Not applicable.

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Shares Trading Summary

        Our common shares are traded on the NYSE under the symbol KOS. The following table shows the quarterly high and low sale prices of our common shares.

	 	2014	 	2013	 	
 
	 	High	 	Low	 	High	 	Low	 	
First Quarter	 	$	11.60	 	$	9.88	 	$	13.05	 	$	10.15	 	
Second Quarter	 	 	11.27	 	 	10.00	 	 	12.17	 	 	10.09	 	
Third Quarter	 	 	11.23	 	 	9.24	 	 	11.15	 	 	9.71	 	
Fourth Quarter	 	 	10.41	 	 	6.96	 	 	11.42	 	 	10.03	 	
        As of February 18, 2015, based on information from the Company's transfer agent, Computershare Trust Company, N.A., the number of holders of record of Kosmos' common shares was 192. On February 18, 2015, the last reported sale price of Kosmos' common shares, as reported on the NYSE, was $8.87 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 tax liability owed by such grantee. The shares withheld from the grantees to settle their tax liability are

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reallocated to the number of shares available for issuance under the LTIP. The following table outlines the total number of shares withheld during fiscal year 2014 and the average price paid per share.

	 	Total Number
of Shares
Withheld/Purchased	 	Average
Price Paid
per Share	 	
 
	 	(In thousands)

January 1, 2014—January 31, 2014	 	 	—	 	$	—	 	
February 1, 2014—February 28, 2014	 	 	7	 	 	10.34	 	
March 1, 2014—March 31, 2014	 	 	—	 	 	—	 	
April 1, 2014—April 30, 2014	 	 	1	 	 	10.99	 	
May 1, 2014—May 31, 2014	 	 	923	 	 	10.46	 	
June 1, 2014—June 30, 2014	 	 	23	 	 	10.48	 	
July 1, 2014—July 31, 2014	 	 	1	 	 	11.10	 	
August 1, 2014—August 31, 2014	 	 	—	 	 	—	 	
September 1, 2014—September 30, 2014	 	 	—	 	 	—	 	
October 1, 2014—October 31, 2014	 	 	2	 	 	10.02	 	
November 1, 2014—November 30, 2014	 	 	—	 	 	—	 	
December 1, 2014—December 31, 2014	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	
Total	 	 	957	 	 	10.46	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
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, 2014, in cumulative total stockholder return on our common shares as measured against the cumulative total return of the S&P 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).

 
	 	 
	 	December 31,	 	 	
 
	 	May 11, 2011	 	 	 	 	 	
 
	 	 	 	2011	 	2012	 	2013	 	2014	 	 	 	 	
Kosmos Energy Ltd. (KOS)	 	$100.00	 	$	68.11	 	$	68.61	 	$	62.11	 	$	46.61	 	 	 	 	
S&P 500 (SPX)	 	100.00	 	 	94.55	 	 	109.36	 	 	143.24	 	 	161.77	 	 	 	 	
SIG Oil Exploration & Production Index (EPX)	 	100.00	 	 	84.33	 	 	78.53	 	 	99.03	 	 	71.71	 	 	 	 	
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Item 6.    Selected Financial Data

        The following selected consolidated financial information set forth below as of and for the five years ended, December 31, 2014, should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8. Financial Statements and Supplementary Data."

Consolidated Statements of Operations Information:

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	2011(1)	 	2010	 	
 
	 	(In thousands, except per share data)
	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	855,877	 	$	851,212	 	$	667,951	 	$	666,912	 	$	—	 	
Gain on sale of assets	 	 	23,769	 	 	—	 	 	—	 	 	—	 	 	—	 	
Other income	 	 	3,092	 	 	941	 	 	3,150	 	 	775	 	 	5,109	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Total revenues and other income	 	 	882,738	 	 	852,153	 	 	671,101	 	 	667,687	 	 	5,109	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	100,122	 	 	96,791	 	 	95,109	 	 	83,551	 	 	—	 	
Exploration expenses	 	 	93,519	 	 	230,314	 	 	100,652	 	 	128,753	 	 	73,126	 	
General and administrative	 	 	135,231	 	 	158,421	 	 	157,087	 	 	111,235	 	 	98,967	 	
Depletion and depreciation	 	 	198,080	 	 	222,544	 	 	185,707	 	 	140,469	 	 	2,423	 	
Interest and other financing costs, net	 	 	45,548	 	 	47,590	 	 	65,425	 	 	132,492	 	 	84,178	 	
Derivatives, net	 	 	(281,853	)	 	17,027	 	 	31,490	 	 	11,777	 	 	28,319	 	
Restructuring charges	 	 	11,742	 	 	—	 	 	—	 	 	—	 	 	—	 	
Doubtful accounts expense	 	 	—	 	 	—	 	 	—	 	 	(39,782	)	 	39,782	 	
Other expenses, net	 	 	2,081	 	 	3,512	 	 	1,475	 	 	149	 	 	1,094	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Total costs and expenses	 	 	304,470	 	 	776,199	 	 	636,945	 	 	568,644	 	 	327,889	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Income (loss) before income taxes	 	 	578,268	 	 	75,954	 	 	34,156	 	 	99,043	 	 	(322,780	)	
Income tax expense (benefit)	 	 	298,898	 	 	166,998	 	 	101,184	 	 	76,686	 	 	(77,108	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Net income (loss)	 	$	279,370	 	$	(91,044	)	$	(67,028	)	$	22,357	 	$	(245,672	)	
Accretion to redemption value of convertible preferred units	 	 	—	 	 	—	 	 	—	 	 	(24,442	)	 	(77,313	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Net income (loss) attributable to common shareholders/unit holders	 	$	279,370	 	$	(91,044	)	$	(67,028	)	$	(2,085	)	$	(322,985	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
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, 2011)(2):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	0.73	 	$	(0.24	)	$	(0.18	)	$	0.09	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Diluted	 	$	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, 2011)(2):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	379,195	 	 	376,819	 	 	371,847	 	 	368,474	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Diluted	 	 	386,119	 	 	376,819	 	 	371,847	 	 	368,607	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	

(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

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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. For the periods presented prior to our corporate reorganization, we do not calculate historical net income (loss) per share attributable to common shareholders because we did not have a common unit of ownership in those periods.

Consolidated Balance Sheets Information:

	 	As of December 31,	 	
 
	 	2014	 	2013	 	2012	 	2011	 	2010	 	
 
	 	(In thousands)
	 	
Cash and cash equivalents	 	$	554,831	 	$	598,108	 	$	515,164	 	$	673,092	 	$	100,415	 	
Total current assets	 	 	1,010,476	 	 	734,961	 	 	750,118	 	 	1,112,481	 	 	559,920	 	
Total property and equipment, net	 	 	1,784,846	 	 	1,522,962	 	 	1,525,762	 	 	1,377,041	 	 	998,000	 	
Total other assets	 	 	177,444	 	 	87,903	 	 	90,243	 	 	62,412	 	 	133,615	 	
Total assets	 	 	2,972,766	 	 	2,345,826	 	 	2,366,123	 	 	2,551,934	 	 	1,691,535	 	
Total current liabilities	 	 	448,771	 	 	219,324	 	 	190,253	 	 	339,607	 	 	482,057	 	
Total long-term liabilities	 	 	1,185,036	 	 	1,134,167	 	 	1,146,964	 	 	1,191,601	 	 	845,383	 	
Total convertible preferred units	 	 	—	 	 	—	 	 	—	 	 	—	 	 	978,506	 	
Total shareholders' equity/unit holdings equity	 	 	1,338,959	 	 	992,335	 	 	1,028,906	 	 	1,020,726	 	 	(614,411	)	
Total liabilities, convertible preferred units and shareholders' equity/unit holdings equity	 	 	2,972,766	 	 	2,345,826	 	 	2,366,123	 	 	2,551,934	 	 	1,691,535	 	
Consolidated Statements of Cash Flows Information:

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	2011	 	2010	 	
 
	 	(In thousands)
	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	443,586	 	$	522,404	 	$	371,530	 	$	364,909	 	$	(191,800	)	
Investing activities	 	 	(347,679	)	 	(324,133	)	 	(402,662	)	 	(385,140	)	 	(589,975	)	
Financing activities	 	 	(139,184	)	 	(115,327	)	 	(126,796	)	 	592,908	 	 	742,685	 	
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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including, without limitation, those set forth in "Cautionary Statement Regarding Forward-Looking Statements" and "Item 1A. Risk Factors." The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this annual report on Form 10-K.

Overview

        Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara), Senegal and Suriname.

Recent Developments

Commodity Prices

        The oil and gas industry as a whole experienced a significant decline in crude oil prices during the second half of 2014. Dated Brent crude, the benchmark for our oil sales, peaked above $115 per barrel in June before falling below $60 at year-end. Excluding the impact of hedges, our December realized price was $62.00 per barrel. February 2015 indices indicate that prices are trending around our December realized price, as the price of crude oil continues to fluctuate.

Corporate

        During the year ended December 31, 2014, we recognized $11.7 million in restructuring charges for employee severance and related benefits, which includes $5.0 million of accelerated non-cash expense related to awards previously granted under the Long-Term Incentive Plan (the "LTIP").

Debt

        In March 2014, the Company amended and restated the then existing commercial debt facility (the "Facility") with a total commitment of $1.5 billion from a number of financial institutions and extended the term to March 31, 2021.

        During August 2014, the Company issued $300.0 million of 7.875% Senior Secured Notes due 2021 ("Senior Notes") and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.

Rig Agreement

        In September 2014, we took delivery of the new build 6th generation drillship "Atwood Achiever" from Atwood Oceanics, Inc. The rig agreement covers 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. We have entered into a rig sharing agreement, whereby two rig slots (estimated to be 130 days in total during 2015 and 30 days during 2016) were assigned to a third-party.

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Ghana

        In early 2014, we deepened a Jubilee Field development well to further appraise the Mahogany discovery, which confirmed an extension of the Mahogany discovery.

        In May 2014, we completed a 3D seismic program of approximately 940 square kilometers over the Tweneboa, Enyenra, and Ntomme ("TEN") development and Wawa appraisal areas in the Deepwater Tano ("DT") Block.

        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 TEN development costs, currently estimated as $4.9 billion (gross). Our portion of GNPC's share is estimated at $49.0 million. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC's TEN production revenues under the terms of the DT petroleum contract.

        Approval was granted by the Government of Ghana and the Ghanaian Environmental Protection Agency in June 2014 to permit the flaring of 500 MMcf of gas per month from the Jubilee Field until the end of October 2014. This limited flaring assisted in the maintenance of existing production levels until the Western Corridor Gas Infrastructure (Jubilee Gas Export) was operational.

        The Jubilee Gas Export commenced in November 2014. The export volumes are expected to increase in 2015 and continue for multiple years.

Morocco (including Western Sahara)

        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. 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. 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 July 2014, we completed a 3D seismic program of approximately 4,300 square kilometers over the Tarhazoute Offshore and Essaouira Offshore blocks. In September 2014, we completed a 3D seismic survey of approximately 5,100 square kilometers over the Cap Boujdour Offshore block.

        In the second quarter of 2014, the FA-1 exploration well on the Foum Assaka Offshore block in the Agadir Basin was determined to be non-commercial and accordingly was plugged and abandoned. BP funded our share of the FA-1 exploration well, subject to a maximum gross spend of $120.0 million. For the year ended December 31, 2014, we expensed $0.7 million associated with the FA-1 well as exploration expenses in the accompanying consolidated statement of operations.

        We entered the first extension period on the Essaouira Offshore block in May 2014, which requires us to drill one exploration well. After the required relinquishment of acreage to enter the first extension period, the Essaouira Offshore block comprises approximately 2.2 million acres.

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        We received final governmental approvals for entering the Tarhazoute Offshore block in early 2014. We are in the initial exploration phase of the petroleum contract, which comprises 1.9 million acres.

        The CB-1 exploration well on the Cap Boujdour Offshore block was spud in December 2014 to test the Al Khayr prospect (formerly named Gargaa). We expect well results during the first quarter of 2015.

Mauritania

        In the fourth quarter of 2014, we drilled the top-hole section of the Tortue-1 exploration well in block C8. As planned, operations were suspended after drilling the top hope section of the well. We expect to complete the drilling of Tortue-1 during the first half of 2015.

Portugal

        In August 2014, we entered into a farm-in agreement with Repsol Exploración, S.A. ("Repsol"), to acquire a non-operated interest in the Camarao, Ameijoa, Mexilhao and Ostra blocks offshore Portugal. As part of the agreement, we will reimburse a portion of Repsol's previously incurred exploration costs, as well as partially carry Repsol's share of the costs of a planned 3D seismic program. Certain governmental approvals and processes are still required to be completed before this acquisition is effective. After completing the acquisition, our participating interest in the blocks will be 31%.

Senegal

        In August 2014, we entered into a farm-in agreement with Timis Corporation Limited, 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 are carrying the full costs of a planned 3D seismic program. Additionally, we will carry the full costs of two contingent exploration wells, subject to a maximum gross cost per well of $120.0 million, should Kosmos elect to drill such wells. We also retain the option to increase our interest 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 September 2014, we commenced a 3D seismic survey of approximately 7,000 square kilometers over the Cayar Offshore Profond and Saint Louis Offshore Profond blocks, which was completed in January 2015.

Suriname

        In Block 42, we received an extension of the initial exploration phase of up to 9 months, which now expires on September 13, 2015.

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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, 2014, 2013 and 2012 are included in the following table:

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands, except per barrel data)
	 	
Sales volumes:	 	 	 	 	 	 	 	 	 	 	
MBbl	 	 	8,728	 	 	7,778	 	 	5,905	 	
Revenues:	 	 	

 	 	
Oil sales	 	$	855,877	 	$	851,212	 	$	667,951	 	
Average sales price per Bbl	 	 	98.06	 	 	109.44	 	 	113.12	 	
Costs:	 	 	

 	 	
Oil production, excluding workovers	 	$	79,648	 	$	57,608	 	$	50,640	 	
Oil production, workovers	 	 	20,474	 	 	39,183	 	 	44,469	 	
​	​	​	​	​	​	​	​	​	​	​	
Total oil production costs	 	$	100,122	 	$	96,791	 	$	95,109	 	
Depletion and depreciation	 	
$	
198,080	 	
$	
222,544	 	
$	
185,707	 	
Average cost per Bbl:	 	 	

 	 	
Oil production, excluding workovers	 	$	9.13	 	$	7.41	 	$	8.58	 	
Oil production, workovers	 	 	2.35	 	 	5.04	 	 	7.53	 	
​	​	​	​	​	​	​	​	​	​	​	
Total oil production costs	 	 	11.48	 	 	12.45	 	 	16.11	 	
Depletion and depreciation	 	 	22.69	 	 	28.61	 	 	31.45	 	
​	​	​	​	​	​	​	​	​	​	​	
Oil production cost and depletion costs	 	$	34.17	 	$	41.06	 	$	47.56	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
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        The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.

Year Ended December 31, 2014 vs. 2013

	 	Years Ended
December 31,	 	 

	 	 	 	Increase
(Decrease)	 	 	 	 	 	 	
 
	 	2014	 	2013	 	 	 	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	855,877	 	$	851,212	 	$	4,665	 	 	 	 	 	 	
Gain on sale of assets	 	 	23,769	 	 	—	 	 	23,769	 	 	 	 	 	 	
Other income	 	 	3,092	 	 	941	 	 	2,151	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Total revenues and other income	 	 	882,738	 	 	852,153	 	 	30,585	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	100,122	 	 	96,791	 	 	3,331	 	 	 	 	 	 	
Exploration expenses	 	 	93,519	 	 	230,314	 	 	(136,795	)	 	 	 	 	 	
General and administrative	 	 	135,231	 	 	158,421	 	 	(23,190	)	 	 	 	 	 	
Depletion and depreciation	 	 	198,080	 	 	222,544	 	 	(24,464	)	 	 	 	 	 	
Interest and other financing costs, net	 	 	45,548	 	 	47,590	 	 	(2,042	)	 	 	 	 	 	
Derivatives, net	 	 	(281,853	)	 	17,027	 	 	(298,880	)	 	 	 	 	 	
Restructuring charges	 	 	11,742	 	 	—	 	 	11,742	 	 	 	 	 	 	
Other expenses, net	 	 	2,081	 	 	3,512	 	 	(1,431	)	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Total costs and expenses	 	 	304,470	 	 	776,199	 	 	(471,729	)	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Income before income taxes	 	 	578,268	 	 	75,954	 	 	502,314	 	 	 	 	 	 	
Income tax expense	 	 	298,898	 	 	166,998	 	 	131,900	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Net income (loss)	 	$	279,370	 	$	(91,044	)	$	370,414	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
        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 due to an increase in sales volumes, nine liftings in 2014 compared to eight in 2013 partially offset by a lower realized price per barrel. We lifted and sold approximately 8,728 MBbl at an average realized price per barrel of $98.06 in 2014 and approximately 7,778 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 due to 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 due to $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

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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 due to a lower depletion rate in 2014 due to an increase in our proved reserves associated with the Jubilee Field.

        Interest and other financing costs.    Interest expense decreased by $2.0 million during the year ended December 31, 2014, as compared to the year ended December 31, 2013, primarily due to 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.

        Income tax expense.    The Company's 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 due to deferred taxes related to the significant mark-to-market gain on derivatives.

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Year Ended December 31, 2013 vs. 2012

	 	Years Ended
December 31,	 	 

	 	 	 	Increase
(Decrease)	 	 	 	 	 	 	
 
	 	2013	 	2012	 	 	 	 	 	 	 	 	
 
	 	(In thousands)
	 	 	 	 	 	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	851,212	 	$	667,951	 	$	183,261	 	 	 	 	 	 	
Other income	 	 	941	 	 	3,150	 	 	(2,209	)	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Total revenues and other income	 	 	852,153	 	 	671,101	 	 	181,052	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	96,791	 	 	95,109	 	 	1,682	 	 	 	 	 	 	
Exploration expenses	 	 	230,314	 	 	97,712	 	 	132,602	 	 	 	 	 	 	
General and administrative	 	 	158,421	 	 	160,027	 	 	(1,606	)	 	 	 	 	 	
Depletion and depreciation	 	 	222,544	 	 	185,707	 	 	36,837	 	 	 	 	 	 	
Interest and other financing costs, net	 	 	47,590	 	 	65,425	 	 	(17,835	)	 	 	 	 	 	
Derivatives, net	 	 	17,027	 	 	31,490	 	 	(14,463	)	 	 	 	 	 	
Other expenses, net	 	 	3,512	 	 	1,475	 	 	2,037	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Total costs and expenses	 	 	776,199	 	 	636,945	 	 	139,254	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Income (loss) before income taxes	 	 	75,954	 	 	34,156	 	 	41,798	 	 	 	 	 	 	
Income tax expense	 	 	166,998	 	 	101,184	 	 	65,814	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
Net loss	 	$	(91,044	)	$	(67,028	)	$	(24,016	)	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	
        Oil and gas revenue.    Oil and gas revenue increased by $183.3 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012, primarily due to an increase in sales volumes. We lifted and sold approximately 7,778 MBbl at an average realized price per barrel of $109.44 in 2013 and approximately 5,905 MBbl at an average realized price per barrel of $113.12 in 2012.

        Oil and gas production.    Oil and gas production costs increased by $1.7 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012. The change is due to an increase in routine operating expenses offset by a reduction in workover and rig equipment costs. During the year ended December 31, 2013, we incurred workover costs for two water injection wells. During the year ended December 31, 2012, we incurred workover costs related to acid jobs for six producing wells.

        Exploration expenses.    Exploration expenses increased by $132.6 million during the year ended December 31, 2013, as compared to the year ended December 31, 2012. During the year ended December 31, 2013, we incurred $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. During the year ended December 31, 2012, we incurred $53.9 million for seismic costs for Morocco, Suriname, Ghana and Cameroon; $32.2 million of unsuccessful well costs, primarily related to the Ghana Teak-4A appraisal well and Ghana Okure-1 exploration well; and $9.9 million of new business costs.

        General and administrative.    General and administrative costs decreased by $1.6 million during the year ended December 31, 2013, as compared to the year ended December 31, 2012. Cash General and administrative costs increased $16.0 million during the year due to an increase in professional fees and compensation and benefits; however, this was partially offset by a $14.4 million decrease in non-cash general and administrative costs associated with our long-term incentive plan.

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        Depletion and depreciation.    Depletion and depreciation increased $36.8 million during the year ended December 31, 2013, as compared with the year ended December 31, 2012, primarily due to depletion related to an increase in production volumes during the year.

        Interest and other financing costs, net.    Interest expense and other financing costs, net decreased by $17.8 million during the year ended December 31, 2013, as compared to the year ended December 31, 2012, primarily due to reduced transaction taxes, decreases in our outstanding debt balance and the mark-to-market changes on our interest rate swaps during the year ended December 31, 2013.

        Derivatives, net.    The decrease in Derivatives, net is due to the change in fair value of the commodity derivative instruments. The change in fair value includes the impact of increases and decreases in the Dated Brent forward curve compared to our executed hedging arrangements and derivatives entered into or settled during each period.

        Income tax expense.    The Company recognized an income tax provision attributable to earnings of $167.0 million and $101.2 million during 2013 and 2012, respectively. The Company's effective tax rates for 2013 and 2012 were 219.9% and 296.2%, respectively. The large effective tax rates for the periods presented are due to losses incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits as well as 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 $65.8 million during the year ended December 31, 2013, as compared with December 31, 2012, primarily due to an increase in pre-tax income from our Ghanaian subsidiary.

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 funding from issuances of equity and debt. In relation to cash flow generated from our operating activities, if we are unable to continuously remove associated natural gas in large quantities from the Jubilee Field, and the potential production restraints caused thereby, then the Company's cash flows from operations will be adversely affected

        While we are presently in a strong financial position, the decline in oil pricing experienced during the fourth quarter of 2014, if prolonged or if further deterioration of pricing continues, could 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. Commodity prices are volatile and future prices cannot be accurately predicted, however, we maintain a hedging program to 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 2015. As such, our 2015 capital budget is based on our development plans for Ghana and our exploration program for 2015.

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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, 2014, 2013 and 2012:

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands)
	 	
Sources of cash and cash equivalents:	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	 	$	443,586	 	$	522,404	 	$	371,530	 	
Proceeds on sale of assets	 	 	58,315	 	 	—	 	 	—	 	
Net proceeds from issuance of senior secured notes	 	 	294,000	 	 	—	 	 	—	 	
Restricted cash	 	 	20,924	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
 	 	 	816,825	 	 	522,404	 	 	371,530	 	
​	​	​	​	​	​	​	​	​	​	​	
Uses of cash and cash equivalents:	 	 	 	 	 	 	 	 	 	 	
Oil and gas assets	 	$	424,535	 	$	317,413	 	$	368,990	 	
Other property	 	 	2,383	 	 	4,970	 	 	9,994	 	
Payments on long-term debt	 	 	400,000	 	 	100,000	 	 	110,000	 	
Purchase of treasury stock	 	 	11,096	 	 	13,101	 	 	8,378	 	
Deferred financing costs	 	 	22,088	 	 	2,226	 	 	8,418	 	
Restricted cash	 	 	—	 	 	1,750	 	 	23,678	 	
​	​	​	​	​	​	​	​	​	​	​	
 	 	 	860,102	 	 	439,460	 	 	529,458	 	
​	​	​	​	​	​	​	​	​	​	​	
Increase (decrease) in cash and cash equivalents	 	$	(43,277	)	$	82,944	 	$	(157,928	)	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
        Net cash provided by operating activities.    Net cash provided by operating activities in 2014 was $443.6 million compared with net cash provided by operating activities of $522.4 million in 2013 and $371.5 million in 2012, respectively. The decrease in cash provided by operating activities in the year ended December 31, 2014 when compared to the same period in 2013 was primarily due to an increase in results from operations offset by a negative change in working capital items. The increase in cash provided by operating activities in 2013 when compared to 2012 was primarily due to an increase in oil and gas revenues and a positive change in working capital items.

        The following table presents our liquidity and financial position as of December 31, 2014:

	 	December 31, 2014	 	
 
	 	(In thousands)
	 	
Cash and cash equivalents	 	$	554,831	 	
Restricted cash	 	 	32,051	 	
Senior Notes at par	 	 	300,000	 	
Drawings under the Facility	 	 	500,000	 	
​	​	​	​	​	
Net debt	 	$	213,118	 	
Availability under the Facility	 	
$	
1,000,000	 	
Availability under the Corporate Revolver	 	 	300,000	 	
Available borrowings plus cash and cash equivalents	 	 	1,854,831	 	
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Capital Expenditures and Investments

        We expect to incur substantial costs as we:

•
develop our discoveries that we determine to be commercially viable;

•
execute our 2015 exploration and appraisal drilling program in our license areas;

•
purchase and analyze seismic and other geological and geophysical data to identify future prospects; and

•
invest in additional oil and natural gas leases and licenses.

        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, 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, and the availability of suitable equipment and qualified personnel. 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 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.

2015 Capital Program

        We estimate we will spend approximately $800 million of capital for the year ending December 31, 2015. This capital expenditure budget consists of:

•
approximately $500 million for developmental related expenditures offshore Ghana; and

•
approximately $300 million for exploration and appraisal related expenditures, including new venture opportunities.

        The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results. 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 these commodities, 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, and the actual cost of exploration, appraisal and development of our oil and natural gas assets.

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

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to those participants were expensed. As a result, we recorded a $2.9 million loss on the extinguishment of debt. As of December 31, 2014, we have $44.6 million of net deferred financing 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, 2014, borrowings under the Facility totaled $500.0 million and the undrawn availability under the Facility was $1.0 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 835—Interest, which requires interest expense to be recognized using the effective interest method. As part of the March 2014 amendment, the Facility's estimated effective interest rate was changed and, accordingly, we adjusted our estimate of deferred interest previously recorded during prior years by $4.5 million, which was recorded as a reduction to interest expense.

        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, 2014, we had no letters of credit issued under the Facility.

        We have the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31 and September 30. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets' reserves and/or resources in Ghana.

        If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions.

        We were in compliance with the financial covenants contained in the Facility as of the September 30, 2014 forecast (the most recent assessment date), which requires the maintenance of:

•
the field life cover ratio (as defined in the glossary), not less than 1.30x; and

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

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

•
the interest cover ratio (as defined in the glossary), not less than 2.25x;

Corporate Revolver

        In November 2012, we secured a Corporate Revolver from a number of financial institutions which, as amended, has an availability of $300.0 million. The Corporate Revolver is available for all

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subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs.

        As of December 31, 2014, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300.0 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 for the lenders are equal to 40% per annum of the respective margin when a commitment is available for utilization.

        The Corporate Revolver has a 3-year availability period that expires on November 20, 2015. 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.

        We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2014 (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. 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 $100.0 million, with additional commitments up to $50.0 million being available if the existing lender increases its commitments or if commitments from new financial institutions are added. The LC Facility provides that we shall maintain cash collateral in an amount equal to at least 75% of all outstanding letters of credit under the LC Facility, provided that during the period of any breach of certain financial covenants, the required cash collateral amount shall increase to 100%. 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, 2014, there were seven outstanding letters of credit totaling $21.5 million under the LC Facility. The LC Facility contains customary cross default provisions.

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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.

        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. 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 plus a make-whole premium. On or after August 1, 2017, the Company may redeem all or a part of the Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:
 	 	 	 	 	
Year	 	Percentage	 	
On or after August 1, 2017, but before August 1, 2018	 	 	103.9	%	
On or after August 1, 2018, but before August 1, 2019	 	 	102.0	%	
On or after August 1, 2019 and thereafter	 	 	100.0	%	
        We may also redeem the Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the Senior Notes at a price equal to the principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

        Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

        If we sell assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

        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

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qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor's Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing.

        Collateral.    The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company's direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share pari passu  in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured.

Contractual Obligations

        The following table summarizes by period the payments due for our estimated contractual obligations as of December 31, 2014:

	 	Payments Due By Year(4)	 	
 
	 	Total	 	2015	 	2016	 	2017	 	2018	 	2019	 	Thereafter	 	
 
	 	(In thousands)
	 	
Principal debt repayments(1)	 	$	800,000	 	$	—	 	$	—	 	$	—	 	$	—	 	$	57,571	 	$	742,429	 	
Interest payments on long-term debt(2)	 	 	352,620	 	 	61,192	 	 	58,898	 	 	61,630	 	 	55,707	 	 	54,207	 	 	60,986	 	
Operating leases	 	 	16,095	 	 	3,260	 	 	3,158	 	 	3,223	 	 	3,323	 	 	3,131	 	 	—	 	
Atwood Achiever drilling rig contract(3)	 	 	486,115	 	 	139,825	 	 	199,920	 	 	146,370	 	 	—	 	 	—	 	 	—	 	

(1)
Includes the scheduled principal maturities for the Senior Notes 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, 2014. 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, 2014, there were no borrowings under the Corporate Revolver.

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

(3)
Commitments calculated using a day rate of $595,000, excluding applicable taxes. The rig commitments reflect the execution of a rig sharing agreement, whereby two rig slots (estimated to be 130 days during 2015 and 30 days during 2016) were assigned to a third-party.

(4)
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.

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        The following table presents maturities by expected debt maturity dates, the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the debt's estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs.

	 	 

	 	 

	 	Liability
Fair Value
at
December 31,
2014	 	 	
 
	 	Years Ending December 31,	 	 	 	 	 	
 
	 	2015	 	2016	 	2017	 	2018	 	2019	 	Thereafter	 	 	 	 	 	
 
	 	(In thousands, except percentages)
	 	 	 	
Fixed rate debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Notes	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	$	300,000	 	$	(255,000	)	 	 	
Fixed interest rate	 	 	7.88	%	 	7.88	%	 	7.88	%	 	7.88	%	 	7.88	%	 	7.88	%	 	 	 	 	 	
Variable rate debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Facility(1)	 	$	—	 	$	—	 	$	—	 	$	—	 	$	57,571	 	$	442,429	 	$	(500,000	)	 	 	
Weighted average interest rate(2)	 	 	3.64	%	 	4.55	%	 	5.25	%	 	5.90	%	 	6.27	%	 	6.89	%	 	 	 	 	 	
Interest rate swaps:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notional debt amount(3)	 	$	16,875	 	$	6,250	 	$	—	 	$	—	 	$	—	 	$	—	 	$	(329	)	 	 	
Fixed rate payable	 	 	2.22	%	 	2.22	%	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	
Variable rate receivable(4)	 	 	0.52	%	 	1.18	%	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	
Notional debt amount(3)	 	$	16,875	 	$	6,250	 	$	—	 	$	—	 	$	—	 	$	—	 	$	(346	)	 	 	
Fixed rate payable	 	 	2.31	%	 	2.31	%	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	
Variable rate receivable(4)	 	 	0.52	%	 	1.18	%	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	
Notional debt amount(3)	 	$	23,137	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	$	(114	)	 	 	
Fixed rate payable	 	 	1.34	%	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	
Variable rate receivable(4)	 	 	0.36	%	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	

(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, 2014. 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, 2014, 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.

        Subsequent to December 31, 2014, we entered into capped interest rate swaps for $200.0 million from January 2016 through December 2018. For $200.0 million of debt that is hedged, we expect to pay an average 1-month LIBOR rate of 1.23% if LIBOR is below 3.0%, and pay the market rate less 1.77% if LIBOR is above 3.0%, net of the capped interest rate swaps.

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, 2014, 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.

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Critical Accounting Policies

        This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities as of the date the financial statements are available to be issued. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in "Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies." We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

        Revenue Recognition.    We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold based on the provisional sales prices. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2014 and 2013, we had no oil and gas imbalances recorded in our consolidated financial statements.

        Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge for accounting purposes, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale occurs.

        Exploration and Development Costs.    We follow the successful efforts method of accounting for our oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are charged to expense as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift crude oil and natural gas to the surface are expensed.

        Receivables.    Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor's ownership interest in oil and natural gas properties we operate, and the owner's ability to pay its obligation, among other things.

        Income Taxes.    We account for income taxes as required by the ASC 740—Income Taxes ("ASC 740"). We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate

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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, 2014 and 2013, 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 taxable 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 taxable income associated with the turn around 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, swaps with calls and purchased puts. We also use interest rate swap 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, are included in accumulated other comprehensive income or loss ("AOCI") in the equity section of the accompanying consolidated balance sheets, and are being transferred to earnings when the hedged transactions settle.

        Estimates of Proved Oil and Natural Gas Reserves.    Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with

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guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:

•
the engineering and geological interpretation of available data;

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

•
the accuracy of various mandated economic assumptions; and

•
the judgments of the persons preparing the estimates.

        Asset Retirement Obligations.    We account for asset retirement obligations as required by the ASC 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation shall be recognized at the asset's acquisition date as if that obligation were incurred on that date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations. Estimating the future restoration and removal costs requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Additionally, asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

        Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance.

        Impairment of Long-Lived Assets.    We review our long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to us are recorded at the lower of carrying amount or fair value less cost to sell.

New Accounting Pronouncements

        In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 prospectively changes the criteria for reporting discontinued operations while enhancing disclosures around disposals of assets whether or not the disposal meets the definition of a discontinued operation. ASU 2014-08 is effective for annual and interim periods beginning after December 15, 2014 with early adoption permitted but only for disposals that have not been reported in financial statements previously issued. The adoption of this new guidance is not expected to have a material impact on the Company's consolidated financial statements.

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        In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

        In June 2014, the FASB issued ASU 2014-12,"Compensation—Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period."  ASU 2014-12 requires a reporting entity to treat a performance target that affects vesting and that could be achieved after the requisite service period as a performance condition. It is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted. The standard may be adopted either prospectively for share-based payment awards granted or modified on or after the effective date, or retrospectively, using a modified retrospective approach. The modified retrospective approach would apply to share-based payment awards outstanding as of the beginning of the earliest annual period presented in the financial statements on adoption, and to all new or modified awards thereafter. The adoption is not expected to have a material impact on the Company's consolidated financial statements.

        In August 2014, the FASB issued ASU 2014-15,"Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern."  ASU 2014-15 requires management to evaluate whether there are conditions and events that raise substantial doubt about the entity's ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. The adoption of this amendment is not expected to have a material impact on the Company's consolidated financial statements.

Item 7A.    Qualitative and Quantitative Disclosures About Market Risk

        The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risks" as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate.

        We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See "Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies, Note 9—Derivative Financial Information and Note 10—Fair Value Measurements" for a description of the accounting procedures we follow relative to our derivative financial instruments.

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        The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year ended December 31, 2014:

	 	Derivative Contracts Assets (Liabilities)	 	
 
	 	Commodities	 	Interest Rates	 	Total	 	
 
	 	(In thousands)
	 	
Fair value of contracts outstanding as of December 31, 2013	 	$	(11,017	)	$	(2,734	)	$	(13,751	)	
Changes in contract fair value	 	 	270,192	 	 	(285	)	 	269,907	 	
Contract maturities	 	 	(6,690	)	 	2,230	 	 	(4,460	)	
​	​	​	​	​	​	​	​	​	​	​	
Fair value of contracts outstanding as of December 31, 2014	 	$	252,485	 	$	(789	)	$	251,696	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Commodity Price Risk

        The Company's revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Crude oil prices in 2014 began the year strong and remained strong through the summer before decreasing rapidly during the fourth quarter. Dated Brent crude, the benchmark against which our oil sales are indexed, peaked above $115 per barrel in June before falling below $60 at year-end.

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, purchased puts and swaps with calls. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.

Commodity Price Sensitivity

        The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of December 31, 2014:

	 	 
	 	 
	 	Weighted Average Dated Brent Price per Bbl	 	Asset
Fair Value
at
December 31,
2014(1)	 	 	
Term	 	Type of Contract	 	MBbl	 	Deferred
Premium
Payable	 	Swap	 	Floor	 	Ceiling	 	Call	 	 	 	 	
2015:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January—December	 	Three-way collars	 	 	4,230	 	$	0.46	 	$	—	 	$	87.43	 	$	110.00	 	$	133.82	 	$	111,955	 	 	
January—December	 	Swaps with calls	 	 	2,000	 	 	—	 	 	93.59	 	 	—	 	 	—	 	 	115.00	 	 	64,820	 	 	
2016:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January—December	 	Purchased puts	 	 	2,000	 	$	3.41	 	$	—	 	$	85.00	 	$	—	 	$	—	 	$	35,620	 	 	
January—December	 	Three-way collars	 	 	2,000	 	 	—	 	 	—	 	 	85.00	 	 	110.00	 	 	135.00	 	 	40,090	 	 	

(1)
Fair values are based on the average forward Dated Brent oil prices on December 31, 2014 which by year are: 2015—$61.25 and 2016—$68.81. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on February 18, 2015 market quotes by year are: 2015—$63.12, 2016—$68.53, and 2017—$71.74.

        In January 2015, we entered into swap contracts and sold put contracts for 2.0 MMBbl from January 2016 through December 2016 with a fixed price of $75.00 per barrel and a short put price of

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$60.00 per barrel. In addition, we sold call contracts for 2.0 MMBbl from January 2017 through December 2017 with a strike price of $85.00 per barrel. The contracts are indexed to Dated Brent prices and we paid a net premium of $3.0 million.

        At December 31, 2014, our open commodity derivative instruments were in a net asset position of $252.5 million. As of December 31, 2014, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $75.4 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $55.8 million.

Interest Rate Derivative Instruments

        See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations" for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.

Interest Rate Sensitivity

        At December 31, 2014, we had floating rate indebtedness outstanding under the Facility of $500.0 million, of which $434.4 million bore interest at floating rates after consideration of our interest rate hedges. The interest rate on this indebtedness as of December 31, 2014 was approximately 3.4%. 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 pay commitment fees on the $1.0 billion of undrawn availability under the Facility and on the $300.0 million of undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.

        As of December 31, 2014, the fair market value of our interest rate swaps was a net liability of approximately $0.8 million. If LIBOR increased by 10%, we estimate it would have a negligible impact on the fair market value of our interest rate swaps.

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Item 8.    Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 
	 	Page	 	
Consolidated Financial Statements of Kosmos Energy Ltd.:	 	 	 	 	
Reports of Independent Registered Public Accounting Firm	 	 	
100	 	
Consolidated Balance Sheets as of December 31, 2014 and 2013	 	 	
102	 	
Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012	 	 	
103	 	
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2014, 2013 and 2012	 	 	
104	 	
Consolidated Statements of Shareholders' Equity for the years ended December 31, 2014, 2013 and 2012	 	 	
105	 	
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	 	 	
106	 	
Notes to Consolidated Financial Statements	 	 	
107	 	
Supplemental Oil and Gas Data (Unaudited)	 	 	
136	 	
Supplemental Quarterly Financial Information (Unaudited)	 	 	
142	 	
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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Kosmos Energy Ltd.

        We have audited the accompanying consolidated balance sheets of Kosmos Energy Ltd. as of December 31, 2014 and 2013, 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, 2014. Our audits also included the financial statement schedules included at Item 15(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kosmos Energy Ltd. at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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.

        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, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas
February 23, 2015

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Kosmos Energy Ltd.

        We have audited Kosmos Energy Ltd.'s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Kosmos Energy Ltd.'s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Annual Report on Internal Control over Financial Reporting appearing in Item 9A. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, Kosmos Energy Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, 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, 2014 and 2013, 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, 2014 of Kosmos Energy Ltd. and our report dated February 23, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas
February 23, 2015

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	 	December 31,	 	
 
	 	2014	 	2013	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	554,831	 	$	598,108	 	
Restricted cash	 	 	15,926	 	 	21,475	 	
Receivables:	 	 	 	 	 	 	 	
Joint interest billings	 	 	60,592	 	 	19,930	 	
Oil sales	 	 	61,731	 	 	281	 	
Other	 	 	41,221	 	 	1,115	 	
Inventories	 	 	55,354	 	 	47,424	 	
Prepaid expenses and other	 	 	25,278	 	 	27,010	 	
Deferred tax assets	 	 	32,268	 	 	19,618	 	
Derivatives	 	 	163,275	 	 	—	 	
​	​	​	​	​	​	​	​	
Total current assets	 	 	1,010,476	 	 	734,961	 	
Property and equipment:	 	 	

Oil and gas properties, net	 	 	1,773,186	 	 	1,508,062	 	
Other property, net	 	 	11,660	 	 	14,900	 	
​	​	​	​	​	​	​	​	
Total property and equipment, net	 	 	1,784,846	 	 	1,522,962	 	
Other assets:	 	 	

Restricted cash	 	 	16,125	 	 	31,500	 	
Long-term receivables—joint interest billings	 	 	14,174	 	 	—	 	
Deferred financing costs, net of accumulated amortization of $33,389 and $24,976 at December 31, 2014 and 2013, respectively	 	 	48,753	 	 	40,111	 	
Long-term deferred tax assets	 	 	9,182	 	 	16,292	 	
Derivatives	 	 	89,210	 	 	—	 	
​	​	​	​	​	​	​	​	
Total assets	 	$	2,972,766	 	$	2,345,826	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
Liabilities and shareholders' equity	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
Accounts payable	 	$	184,400	 	$	94,172	 	
Accrued liabilities	 	 	201,967	 	 	115,212	 	
Deferred tax liability	 	 	61,683	 	 	—	 	
Derivatives	 	 	721	 	 	9,940	 	
​	​	​	​	​	​	​	​	
Total current liabilities	 	 	448,771	 	 	219,324	 	
Long-term liabilities:	 	 	

Long-term debt	 	 	794,269	 	 	900,000	 	
Derivatives	 	 	68	 	 	3,811	 	
Asset retirement obligations	 	 	44,023	 	 	39,596	 	
Deferred tax liability	 	 	337,961	 	 	170,226	 	
Other long-term liabilities	 	 	8,715	 	 	20,534	 	
​	​	​	​	​	​	​	​	
Total long-term liabilities	 	 	1,185,036	 	 	1,134,167	 	
Shareholders' equity:	 	 	

Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2014 and 2013	 	 	—	 	 	—	 	
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 392,443,048 and 391,974,287 issued at December 31, 2014 and 2013, respectively	 	 	3,924	 	 	3,920	 	
Additional paid-in capital	 	 	1,860,190	 	 	1,781,535	 	
Accumulated deficit	 	 	(494,850	)	 	(774,220	)	
Accumulated other comprehensive income	 	 	767	 	 	2,158	 	
Treasury stock, at cost, 5,555,088 and 4,400,135 shares at December 31, 2014 and 2013, respectively	 	 	(31,072	)	 	(21,058	)	
​	​	​	​	​	​	​	​	
Total shareholders' equity	 	 	1,338,959	 	 	992,335	 	
​	​	​	​	​	​	​	​	
Total liabilities and shareholders' equity	 	$	2,972,766	 	$	2,345,826	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	855,877	 	$	851,212	 	$	667,951	 	
Gain on sale of assets	 	 	23,769	 	 	—	 	 	—	 	
Other income	 	 	3,092	 	 	941	 	 	3,150	 	
​	​	​	​	​	​	​	​	​	​	​	
Total revenues and other income	 	 	882,738	 	 	852,153	 	 	671,101	 	
Costs and expenses:	 	 	

 	 	
Oil and gas production	 	 	100,122	 	 	96,791	 	 	95,109	 	
Exploration expenses	 	 	93,519	 	 	230,314	 	 	100,652	 	
General and administrative	 	 	135,231	 	 	158,421	 	 	157,087	 	
Depletion and depreciation	 	 	198,080	 	 	222,544	 	 	185,707	 	
Interest and other financing costs, net	 	 	45,548	 	 	47,590	 	 	65,425	 	
Derivatives, net	 	 	(281,853	)	 	17,027	 	 	31,490	 	
Restructuring charges	 	 	11,742	 	 	—	 	 	—	 	
Other expenses, net	 	 	2,081	 	 	3,512	 	 	1,475	 	
​	​	​	​	​	​	​	​	​	​	​	
Total costs and expenses	 	 	304,470	 	 	776,199	 	 	636,945	 	
​	​	​	​	​	​	​	​	​	​	​	
Income before income taxes	 	 	
578,268	 	 	
75,954	 	 	
34,156	 	
Income tax expense	 	 	298,898	 	 	166,998	 	 	101,184	 	
​	​	​	​	​	​	​	​	​	​	​	
Net income (loss)	 	
$	
279,370	 	
$	
(91,044	
)	
$	
(67,028	
)	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Net income (loss) per share attributable to common shareholders:	 	 	

 	 	
Basic	 	$	0.73	 	$	(0.24	)	$	(0.18	)	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Diluted	 	$	0.72	 	$	(0.24	)	$	(0.18	)	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Weighted average number of shares used to compute net income (loss) per share:	 	 	

 	 	
Basic	 	 	379,195	 	 	376,819	 	 	371,847	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Diluted	 	 	386,119	 	 	376,819	 	 	371,847	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
Net income (loss)	 	$	279,370	 	$	(91,044	)	$	(67,028	)	
Other comprehensive income :	 	 	 	 	 	 	 	 	 	 	
Reclassification adjustments for derivative (gains) losses included in net income (loss)	 	 	(1,391	)	 	(1,527	)	 	163	 	
Income tax benefit	 	 	—	 	 	—	 	 	1,027	 	
​	​	​	​	​	​	​	​	​	​	​	
Other comprehensive income (loss)	 	 	(1,391	)	 	(1,527	)	 	1,190	 	
​	​	​	​	​	​	​	​	​	​	​	
Comprehensive income (loss)	 	$	277,979	 	$	(92,571	)	$	(65,838	)	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(In thousands)

	 	Common Shares	 	 
	 	 
	 	Accumulated
Other
Comprehensive
Income	 	 

 
	 	 	 	Additional
Paid-in
Capital	 	Accumulated
Deficit	 	 	 	Treasury
Stock	 	 

	 	Shares	 	Amount	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2011	 	 	390,531	 	$	3,905	 	$	1,629,453	 	$	(616,148	)	$	3,522	 	$	(6	)	$	1,020,726	 	 	 	 	 	 	 	 	 	 	 	 	
Equity-based compensation	 	 	—	 	 	—	 	 	83,423	 	 	—	 	 	—	 	 	—	 	 	83,423	 	 	 	 	 	 	 	 	 	 	 	 	
Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	163	 	 	—	 	 	163	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted stock awards	 	 	893	 	 	9	 	 	(9	)	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted stock forfeitures	 	 	—	 	 	—	 	 	13	 	 	—	 	 	—	 	 	(13	)	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Purchase of treasury stock	 	 	—	 	 	—	 	 	—	 	 	—	 	 	—	 	 	(8,378	)	 	(8,378	)	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	—	 	 	—	 	 	—	 	 	(67,028	)	 	—	 	 	—	 	 	(67,028	)	 	 	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2012	 	 	391,424	 	 	3,914	 	 	1,712,880	 	 	(683,176	)	 	3,685	 	 	(8,397	)	 	1,028,906	 	 	 	 	 	 	 	 	 	 	 	 	
Equity-based compensation	 	 	—	 	 	—	 	 	69,101	 	 	—	 	 	—	 	 	—	 	 	69,101	 	 	 	 	 	 	 	 	 	 	 	 	
Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	(1,527	)	 	—	 	 	(1,527	)	 	 	 	 	 	 	 	 	 	 	 	
Restricted stock awards and units	 	 	550	 	 	6	 	 	(6	)	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted stock forfeitures	 	 	—	 	 	—	 	 	6	 	 	—	 	 	—	 	 	(6	)	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Purchase of treasury stock	 	 	—	 	 	—	 	 	(446	)	 	—	 	 	—	 	 	(12,655	)	 	(13,101	)	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	—	 	 	—	 	 	—	 	 	(91,044	)	 	—	 	 	—	 	 	(91,044	)	 	 	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2013	 	 	391,974	 	 	3,920	 	 	1,781,535	 	 	(774,220	)	 	2,158	 	 	(21,058	)	 	992,335	 	 	 	 	 	 	 	 	 	 	 	 	
Equity-based compensation	 	 	—	 	 	—	 	 	79,741	 	 	—	 	 	—	 	 	—	 	 	79,741	 	 	 	 	 	 	 	 	 	 	 	 	
Derivatives, net	 	 	—	 	 	—	 	 	—	 	 	—	 	 	(1,391	)	 	—	 	 	(1,391	)	 	 	 	 	 	 	 	 	 	 	 	
Restricted stock awards and units	 	 	469	 	 	4	 	 	(4	)	 	—	 	 	—	 	 	—	 	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Restricted stock forfeitures	 	 	—	 	 	—	 	 	2	 	 	—	 	 	—	 	 	(2	)	 	—	 	 	 	 	 	 	 	 	 	 	 	 	
Purchase of treasury stock	 	 	—	 	 	—	 	 	(1,084	)	 	—	 	 	—	 	 	(10,012	)	 	(11,096	)	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	 	—	 	 	—	 	 	—	 	 	279,370	 	 	—	 	 	—	 	 	279,370	 	 	 	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2014	 	 	392,443	 	$	3,924	 	$	1,860,190	 	$	(494,850	)	$	767	 	$	(31,072	)	$	1,338,959	 	 	 	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	 	 	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	​	 	 	 	 	 	 	 	 	 	 	 	

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	279,370	 	$	(91,044	)	$	(67,028	)	
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	
Depletion, depreciation and amortization	 	 	208,628	 	 	233,598	 	 	194,691	 	
Deferred income taxes	 	 	216,409	 	 	82,380	 	 	80,036	 	
Unsuccessful well costs	 	 	1,105	 	 	107,565	 	 	32,229	 	
Change in fair value of derivatives	 	 	(271,298	)	 	23,093	 	 	18,465	 	
Cash settlements on derivatives	 	 	4,460	 	 	(33,411	)	 	(28,594	)	
Equity-based compensation	 	 	79,541	 	 	69,026	 	 	83,423	 	
Gain on sale of assets	 	 	(23,769	)	 	—	 	 	—	 	
Loss on extinguishment of debt	 	 	2,898	 	 	—	 	 	5,342	 	
Other	 	 	(3,875	)	 	4,916	 	 	7,890	 	
Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	
(Increase) decrease in receivables	 	 	(156,192	)	 	111,677	 	 	176,905	 	
Increase in inventories	 	 	(8,100	)	 	(16,763	)	 	(7,385	)	
(Increase) decrease in prepaid expenses and other	 	 	1,732	 	 	(16,540	)	 	3,443	 	
Increase (decrease) in accounts payable	 	 	90,228	 	 	(34,683	)	 	(126,401	)	
Increase (decrease) in accrued liabilities	 	 	22,449	 	 	82,590	 	 	(1,486	)	
​	​	​	​	​	​	​	​	​	​	​	
Net cash provided by operating activities	 	 	443,586	 	 	522,404	 	 	371,530	 	
Investing activities	 	 	

 	 	
Oil and gas assets	 	 	(424,535	)	 	(317,413	)	 	(368,990	)	
Other property	 	 	(2,383	)	 	(4,970	)	 	(9,994	)	
Proceeds from sale of assets	 	 	58,315	 	 	—	 	 	—	 	
Restricted cash	 	 	20,924	 	 	(1,750	)	 	(23,678	)	
​	​	​	​	​	​	​	​	​	​	​	
Net cash used in investing activities	 	 	(347,679	)	 	(324,133	)	 	(402,662	)	
Financing activities	 	 	

 	 	
Payments on long-term debt	 	 	(400,000	)	 	(100,000	)	 	(110,000	)	
Net proceeds from issuance of senior secured notes	 	 	294,000	 	 	—	 	 	—	 	
Purchase of treasury stock	 	 	(11,096	)	 	(13,101	)	 	(8,378	)	
Deferred financing costs	 	 	(22,088	)	 	(2,226	)	 	(8,418	)	
​	​	​	​	​	​	​	​	​	​	​	
Net cash used in financing activities	 	 	(139,184	)	 	(115,327	)	 	(126,796	)	
​	​	​	​	​	​	​	​	​	​	​	
Net increase (decrease) in cash and cash equivalents	 	 	(43,277	)	 	82,944	 	 	(157,928	)	
Cash and cash equivalents at beginning of period	 	 	598,108	 	 	515,164	 	 	673,092	 	
​	​	​	​	​	​	​	​	​	​	​	
Cash and cash equivalents at end of period	 	$	554,831	 	$	598,108	 	$	515,164	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Supplemental cash flow information	 	 	 	 	 	 	 	 	 	 	
Cash paid for:	 	 	 	 	 	 	 	 	 	 	
Interest	 	$	23,182	 	$	36,313	 	$	41,234	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Income taxes	 	$	108,068	 	$	68,437	 	$	22,020	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

1. Organization

        Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.'s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms "Kosmos," the "Company," "we," "us," "our," "ours," and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise.

        Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margin. Our assets include existing production and other major development projects offshore Ghana, as well as exploration licenses with significant hydrocarbon potential offshore Ireland, Mauritania, Morocco (including Western Sahara), Senegal and Suriname. 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 impact on our reported net income, current assets, total assets, current liabilities, total liabilities or shareholders' equity.

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

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Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

the Facility, whichever is greater. As of December 31, 2014 and 2013, we had $15.9 million and $18.6 million, respectively, in current restricted cash to meet this requirement.

        In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post 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, 2014 and 2013, we had zero and $2.9 million, respectively, of current restricted cash and $16.1 million and $31.5 million, respectively, of long-term restricted cash used to cash collateralize performance guarantees related to our petroleum contracts.

Receivables

        Our receivables consist of joint interest billings, oil sales and other receivables. For our oil sales receivable, we require a letter of credit to be posted to secure the outstanding receivable. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. We determine our allowance by considering the length of time past due, future net revenues of the debtor's ownership interest in oil and natural gas properties we operate, and the owner's ability to pay its obligation, among other things. We did not have any allowance for doubtful accounts as of December 31, 2014 and 2013.

Inventories

        Inventories consisted of $55.3 million and $45.8 million of materials and supplies and $0.1 million and $1.6 million of hydrocarbons as of December 31, 2014 and 2013, respectively. The Company's materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or 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.

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Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

        The Company evaluates unproved property, other than well related costs, periodically for impairment. These costs are generally related to the acquisition of leasehold costs. 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 410—Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset's acquisition date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion and depreciation in the consolidated statement of operations.

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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 360—Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. An impairment loss shall be measured as the amount by which the carrying amount of a long-lived asset exceeds its fair value. Assets to be disposed of and assets not expected to provide any future service potential to the Company are recorded at the lower of carrying amount or fair value less cost to sell.

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, swaps with calls and purchased puts. We also use interest rate swap 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, are included in accumulated other comprehensive income or loss ("AOCI") in the equity section of the accompanying consolidated balance sheets, and are being transferred to earnings when the hedged transactions settle. See Note 9—Derivative Financial Instruments.

Estimates of Proved Oil and Natural Gas Reserves

        Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the Securities and Exchange Commission ("SEC") and the Financial Accounting Standards Board ("FASB"). The accuracy of these reserve estimates is a function of:

•
the engineering and geological interpretation of available data;

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

•
the accuracy of various mandated economic assumptions; and

•
the judgments of the persons preparing the estimates.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

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, 2014 and 2013, we had no oil and gas imbalances recorded in our consolidated financial statements.

        Our oil and gas revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.

Equity-based Compensation

        For equity-based compensation awards, compensation expense is recognized in the Company's financial statements over the awards' vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock 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 tax withholding requirements and were not part of a formal stock repurchase plan. The remainder of our treasury stock is forfeited restricted stock awards granted under our long-term incentive plan.

Income Taxes

        The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. On a quarterly basis, management evaluates

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Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

        We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized.

Foreign Currency Translation

        The U.S. dollar is the functional currency for all of the Company's material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period.

Concentration of Credit Risk

        Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long-term material adverse effect on our financial position or results of operations.

Recent Accounting Standards

        In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 prospectively changes the criteria for reporting discontinued operations while enhancing disclosures around disposals of assets whether or not the disposal meets the definition of a discontinued operation. ASU 2014-08 is effective for annual and interim periods beginning after December 31, 2014 with early adoption permitted but only for disposals that have not been reported in financial statements previously issued. The adoption of this new guidance is not expected to have a material impact on the Company's consolidated financial statements.

        In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

2. Accounting Policies (Continued)

        In June 2014, the FASB issued ASU 2014-12,"Compensation-Stock Compensation (Topic 718): Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period."  ASU 2014-12 requires a reporting entity to treat a performance target that affects vesting and that could be achieved after the requisite service period as a performance condition. It is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted. The standard may be adopted either prospectively for share-based payment awards granted or modified on or after the effective date, or retrospectively, using a modified retrospective approach. The modified retrospective approach would apply to share-based payment awards outstanding as of the beginning of the earliest annual period presented in the financial statements on adoption, and to all new or modified awards thereafter. The adoption is not expected to have a material impact on the Company's consolidated financial statements.

        In August 2014, the FASB issued ASU 2014-15,"Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern."  ASU 2014-15 requires management to evaluate whether there are conditions and events that raise substantial doubt about the entity's ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. The adoption of this amendment is not expected to have a material impact on the Company's consolidated financial statements.

3. Acquisitions and Divestitures

        In November 2012, we finalized the assignment of a 50% participating interest in our blocks offshore Suriname, Block 42 and Block 45, to Chevron. We retain a 50% participating interest in the blocks and remain the operator for the exploration phase of the petroleum contracts. In the fourth quarter of 2012, we received $23.7 million in reimbursement of previously incurred expenses as a result of closing the transaction. Accordingly, exploration expense and general and administrative expense were reduced by $22.7 million and $1.0 million, respectively.

        In January 2013, we closed 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. Government approvals for this acquisition were finalized in November 2013.

        In April 2013, we entered into a farm-in agreement with Antrim Energy Inc., whereby we acquired a 75% participating interest and operatorship, covering Licensing Option 11/5 offshore the west coast of Ireland. As part of the agreement, we reimbursed a portion of previously-incurred exploration costs, as well as carry the partner on future 3D seismic costs.

        In April 2013, we entered into a farm-in agreement with Europa Oil & Gas (Holdings) plc, whereby we acquired an 85% participating interest and operatorship, covering Licensing Option 11/7 and 11/8 offshore the west coast of Ireland. As part of the agreement, we reimbursed a portion of previously incurred exploration costs, as well as carry the partner on future 3D seismic costs. Contingent upon an election by us and our partner to enter into a subsequent exploration drilling phase on one or both of the blocks, we will also fund 100% of the costs of the first exploration well on

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Notes to Consolidated Financial Statements (Continued)

3. Acquisitions and Divestitures (Continued)

each block, subject to an investment cap of $90.0 million and $110.0 million, respectively, on each block.

        In August 2013, final government approvals and processes were completed for the acquisition of the additional 18.8% participating interest in the Foum Assaka block in the Agadir Basin offshore Morocco from Pathfinder Hydrocarbon Ventures Limited ("Pathfinder"), a wholly owned subsidiary of Fastnet Oil and Gas Plc ("Fastnet"), one of our block partners.

        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 will 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. 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 will pay 150% of its share of costs of a 3D seismic survey capped at $25.0 million and one exploration well capped at $100.0 million. In the event the exploration well is successful, Cairn will pay 200% of its share of costs on two appraisal wells capped at $100.0 million per well. Additionally, Cairn will contribute $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, 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 will carry the full costs of a planned 3D seismic program. Additionally, we will carry the full costs of two contingent exploration wells, subject to a maximum gross cost per well of $120.0 million, should Kosmos elect to drill such wells. 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 February 2015, we entered into 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 will acquire a 30% non-operated working interest in each of the contract areas. Chevron will pay a disproportionate share of the costs of one exploration well and a second contingent exploration well, subject to maximum expenditure caps. In addition, Chevron will pay its proportionate share of

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Notes to Consolidated Financial Statements (Continued)

3. Acquisitions and Divestitures (Continued)

previously incurred exploration costs. Chevron will not initially fund drilling of the Tortue prospect, but retains the option to participate in this prospect after the transaction is completed. The transaction is subject to customary closing conditions. Once these farm-out agreements become effective, Kosmos, Chevron and SMHPM's participating interest in Block C8, Block C12 and Block C13 will be 60%, 30% and 10%, respectively.

4. Joint Interest Billings

        The Company's joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.

        In 2014, the Ghana National Petroleum Corporation ("GNPC") notified us and our block partners 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 GNPC's TEN production revenues under the terms of the DT petroleum contract. As of December 31, 2014, the joint interest billing receivables due from GNPC for the TEN development costs were $14.2 million, which were classified as long-term on the consolidated balance sheets.

5. Property and Equipment

        Property and equipment is stated at cost and consisted of the following:

	 	December 31,	 	
 
	 	2014	 	2013	 	
 
	 	(In thousands)
	 	
Oil and gas properties:	 	 	 	 	 	 	 	
Proved properties	 	$	1,156,868	 	$	801,348	 	
Unproved properties	 	 	363,717	 	 	524,257	 	
Support equipment and facilities	 	 	968,722	 	 	710,289	 	
​	​	​	​	​	​	​	​	
Total oil and gas properties	 	 	2,489,307	 	 	2,035,894	 	
Less: accumulated depletion	 	 	(716,121	)	 	(527,832	)	
​	​	​	​	​	​	​	​	
Oil and gas properties, net	 	 	1,773,186	 	 	1,508,062	 	
Other property	 	 	
33,718	 	 	
31,658	 	
Less: accumulated depreciation	 	 	(22,058	)	 	(16,758	)	
​	​	​	​	​	​	​	​	
Other property, net	 	 	11,660	 	 	14,900	 	
​	​	​	​	​	​	​	​	
Total property and equipment, net	 	$	1,784,846	 	$	1,522,962	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
        We recorded depletion expense of $188.3 million, $213.7 million and $178.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

6. Suspended Well Costs

        The Company capitalizes exploratory well costs into 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. The well costs are charged to expense if the exploratory well is determined to be impaired.

        The following table reflects the Company's capitalized exploratory well costs on completed wells as of and during years ended December 31, 2014, 2013 and 2012. The table excludes $1.1 million, $78.5 million and $29.6 million in costs that were capitalized and subsequently expensed during the same year for the years ended December 31, 2014, 2013 and 2012, respectively. During 2014, the exploratory well costs associated with the TEN development were reclassified to proved property.

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands)
	 	
Beginning balance	 	$	376,166	 	$	372,492	 	$	267,592	 	
Additions to capitalized exploratory well costs pending the determination of proved reserves	 	 	71,039	 	 	32,804	 	 	107,527	 	
Reclassification due to determination of proved reserves	 	 	(220,491	)	 	—	 	 	—	 	
Capitalized exploratory well costs charged to expense	 	 	—	 	 	(29,130	)	 	(2,627	)	
​	​	​	​	​	​	​	​	​	​	​	
Ending balance	 	$	226,714	 	$	376,166	 	$	372,492	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
        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,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands, except well counts)
	 	
Exploratory well costs capitalized for a period of one year or less	 	$	16,814	 	$	11,426	 	$	106,635	 	
Exploratory well costs capitalized for a period one to two years	 	 	40,865	 	 	229,140	 	 	179,933	 	
Exploratory well costs capitalized for a period three to five years	 	 	169,035	 	 	135,600	 	 	85,924	 	
​	​	​	​	​	​	​	​	​	​	​	
Ending balance	 	$	226,714	 	$	376,166	 	$	372,492	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	 	 	5	 	 	8	 	 	7	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
        As of December 31, 2014, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to Mahogany, Teak-1, Teak-2 and Akasa discoveries in the West Cape Three Points ("WCTP") Block and the Wawa discovery in the Deepwater Tano ("DT") Block, which are all in Ghana.

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Notes to Consolidated Financial Statements (Continued)

6. Suspended Well Costs (Continued)

        Mahogany—Three appraisal wells have been drilled. Additionally, we deepened a development well in the Jubilee Field to further appraise the Mahogany discovery. Following additional evaluation, a decision regarding commerciality of the Mahogany discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana's Ministry of Energy, as required under the WCTP petroleum contract.

        Teak-1 Discovery—Two appraisal wells have been drilled. Following additional evaluation, a decision regarding commerciality of the Teak-1 discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana's Ministry of Energy, as required under the WCTP petroleum contract.

        Teak-2 Discovery—We have performed a gauge installation on the well and reprocessed seismic data. Following additional evaluation, a decision regarding commerciality of the Teak-2 discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana's Ministry of Energy, as required under the WCTP petroleum contract.

        Akasa Discovery—We performed a drill stem test and gauge installation on the discovery well and drilled one appraisal well, the Akasa-2A. Following additional evaluation, a decision regarding commerciality of the Akasa discovery is expected to be made by the WCTP Block partners in early 2015. Within six months of such a declaration, a PoD would be prepared and submitted to Ghana's Ministry of Energy, as required under the WCTP petroleum contract.

        Wawa Discovery—We are currently reprocessing 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 is expected to be made by the DT Block partners in 2016. Within six months of such declaration, a PoD would be prepared and submitted to Ghana's Ministry of Energy, as required under the DT petroleum contract.

7. Accrued Liabilities

        Accrued liabilities consisted of the following:

	 	December 31,	 	
 
	 	2014	 	2013	 	
 
	 	(In thousands)
	 	
Accrued liabilities:	 	 	 	 	 	 	 	
Accrued exploration, development and production	 	$	139,393	 	$	73,976	 	
Accrued general and administrative expenses	 	 	21,926	 	 	4,255	 	
Accrued taxes other than income	 	 	20,315	 	 	15,188	 	
Accrued interest	 	 	10,271	 	 	—	 	
Income taxes	 	 	9,233	 	 	20,379	 	
Accrued other	 	 	829	 	 	1,414	 	
​	​	​	​	​	​	​	​	
 	 	$	201,967	 	$	115,212	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

8. Debt

        Debt consisted of the following:

	 	December 31,	 	
 
	 	2014	 	2013	 	
 
	 	(In thousands)
	 	
Outstanding debt principal balances:	 	 	 	 	 	 	 	
Facility	 	$	500,000	 	$	900,000	 	
Senior Notes	 	 	300,000	 	 	—	 	
​	​	​	​	​	​	​	​	
Total	 	 	800,000	 	 	900,000	 	
Unamortized issuance discounts	 	 	(5,731	)	 	—	 	
​	​	​	​	​	​	​	​	
Long-term debt	 	$	794,269	 	$	900,000	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
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, including the International Finance Corporation. 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, 2014, we have $44.6 million of net deferred financing 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, 2014, borrowings under the Facility totaled $500.0 million and the undrawn availability under the Facility was $1.0 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 835—Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility. As part of the March 2014 amendment, the Facility's estimated effective interest rate was changed and, accordingly, we adjusted our estimate of deferred interest previously recorded during prior years by $4.5 million, which was recorded as a reduction to interest expense.

        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

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Notes to Consolidated Financial Statements (Continued)

8. Debt (Continued)

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, 2014, we had no letters of credit issued under the Facility.

        Kosmos has the right to cancel all the undrawn commitments under the Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined each year on March 31 and September 30. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets' reserves and/or resources in Ghana.

        If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. The Facility contains customary cross default provisions.

        We were in compliance with the financial covenants contained in the Facility as of the September 30, 2014 (the most recent assessment date).

Corporate Revolver

        In November 2012, we secured a Corporate Revolver from a number of financial institutions which, as amended, has an availability of $300.0 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, 2014, we have $2.9 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term, or November 20, 2015.

        As of December 31, 2014, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300.0 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 for the lenders are equal to 40% per annum of the respective margin when a commitment is available for utilization.

        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, 2014 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

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Notes to Consolidated Financial Statements (Continued)

8. Debt (Continued)

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 $100.0 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. 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, 2014, there were seven outstanding letters of credit totaling $21.5 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.

        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. 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 plus 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

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

8. Debt (Continued)

principal amount of the Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

        Upon the occurrence of a change of control triggering event as defined under the Indenture, the Company will be required to make an offer to repurchase the Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

        If we sell assets, under certain circumstances outlined in the Indenture, we will be required to use the net proceeds to make an offer to purchase the Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

        Covenants.    The Indenture restricts our ability and the ability of our restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of our subsidiaries to make dividends or other payments to us, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the Senior Notes are assigned an investment grade rating by both Standard & Poor's Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing.

        Collateral.    The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all currently outstanding shares, additional shares, dividends or other distributions paid in respect of such shares or any other property derived from such shares, in each case held by us in relation to the Company's direct subsidiary, Kosmos Energy Holdings, pursuant to the terms of the Charge over Shares of Kosmos Energy Holdings dated November 23, 2012, as amended and restated on March 14, 2014, between the Company and BNP Paribas as Security and Intercreditor Agent. The Senior Notes share pari passu  in the benefit of such equitable charge based on the respective amounts of the obligations under the Indenture and the amount of obligations under the Corporate Revolver. The Guarantees are not secured.

        At December 31, 2014, the estimated repayments of debt during the five years and thereafter are as follows:

	 	Payments Due by Year	 	
 
	 	2015	 	2016	 	2017	 	2018	 	2019	 	Thereafter	 	
 
	 	(In thousands)
	 	
Principal debt repayments(1)	 	$	—	 	$	—	 	$	—	 	$	—	 	$	57,571	 	$	742,429	 	

(1)
Includes the scheduled principal maturities for the Senior Notes 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, 2014. 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, 2014, there were no borrowings under the Corporate Revolver.

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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,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands)
	 	
Interest expense	 	$	57,876	 	$	49,317	 	$	56,298	 	
Amortization—deferred financing costs	 	 	10,548	 	 	11,054	 	 	8,984	 	
Loss on extinguishment of debt	 	 	2,898	 	 	—	 	 	5,342	 	
Capitalized interest	 	 	(20,577	)	 	(13,074	)	 	(10,302	)	
Deferred interest	 	 	(3,562	)	 	1,658	 	 	3,584	 	
Interest rate derivatives, net	 	 	(1,106	)	 	(1,090	)	 	2,627	 	
Interest income	 	 	(529	)	 	(275	)	 	(1,108	)	
​	​	​	​	​	​	​	​	​	​	​	
Interest and other financing costs, net	 	$	45,548	 	$	47,590	 	$	65,425	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
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 820—Fair Value Measurements and Disclosures.

Oil Derivative Contracts

        The following table sets forth the volumes in barrels underlying the Company's outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of December 31, 2014.

	 	 
	 	 
	 	Weighted Average Dated Brent Price per Bbl	 	
Term	 	Type of Contract	 	MBbl	 	Deferred
Premium
Payable	 	Swap	 	Floor	 	Ceiling	 	Call	 	
2015:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January—December	 	Three-way collars	 	 	4,230	 	$	0.46	 	$	—	 	$	87.43	 	$	110.00	 	$	133.82	 	
January—December	 	Swaps with calls	 	 	2,000	 	 	—	 	 	93.59	 	 	—	 	 	—	 	 	115.00	 	
2016:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January—December	 	Purchased puts	 	 	2,000	 	$	3.41	 	$	—	 	$	85.00	 	$	—	 	$	—	 	
January—December	 	Three-way collars	 	 	2,000	 	 	—	 	 	—	 	 	85.00	 	 	110.00	 	 	135.00	 	
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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

9. Derivative Financial Instruments (Continued)

        In January 2015, we entered into swap contracts and sold put contracts for 2.0 MMBbl from January 2016 through December 2016 with a fixed price of $75.00 per barrel and a short put price of $60.00 per barrel. In addition, we sold call contracts for 2.0 MMBbl from January 2017 through December 2017 with a strike price of $85.00 per barrel. The contracts are indexed to Dated Brent prices and we paid a net premium of $3.0 million.

Interest Rate Swaps Derivative Contracts

        The following table summarizes our open interest rate swaps as of December 31, 2014, whereby we pay a fixed rate of interest and the counterparty pays a variable LIBOR-based rate:
 	 	 	 	 	 	 	 	 	
Term	 	Weighted Average
Notional Amount	 	Weighted Average
Fixed Rate	 	Floating Rate	
 
	 	(In thousands)

	
January 2015—December 2015	 	 	45,319	 	 	2.03	%	6-month LIBOR	
January 2016—June 2016	 	 	12,500	 	 	2.27	%	6-month LIBOR	
        Subsequent to December 31, 2014, we entered into capped interest rate swaps for $200.0 million from January 2016 through December 2018. For $200.0 million of debt that is hedged, we expect to pay an average 1-month LIBOR rate of 1.23% if LIBOR is below 3.0%, and pay the market rate less 1.77% if LIBOR is above 3.0%, net of the capped interest rate swaps.

        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 are recognized in earnings during the period of change. The effective portions of the discontinued hedges as of May 31, 2010, are included in AOCI in the equity section of the accompanying consolidated balance sheets, and are being transferred to earnings when the hedged transaction settles. The Company expects to reclassify $0.6 million of gains from AOCI to interest expense within the next 12 months. See Note 10—Fair Value Measurements for additional information regarding the Company's derivative instruments.

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Notes to Consolidated Financial Statements (Continued)

9. Derivative Financial Instruments (Continued)

        The following tables disclose the Company's derivative instruments as of December 31, 2014 and 2013 and gain/(loss) from derivatives during the years ended December 31, 2014, 2013 and 2012:

	 	 
	 	Estimated Fair Value
Asset (Liability)	 	

	 	December 31,	 	
Type of Contract	 	Balance Sheet Location	 	2014	 	2013	 	

	 	(In thousands)
	 	
Derivatives not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	
Derivative assets:	 	 	 	 	 	 	 	 	 	
Commodity(1)	 	Derivatives assets—current	 	$	163,275	 	$	—	 	
Commodity(2)	 	Derivatives assets—long-term	 	 	89,210	 	 	—	 	
Derivative liabilities:	 	 	 	 	

Commodity(3)	 	Derivatives liabilities—current	 	 	—	 	 	(7,873	)	
Interest rate	 	Derivatives liabilities—current	 	 	(721	)	 	(2,067	)	
Commodity(4)	 	Derivatives liabilities—long-term	 	 	—	 	 	(3,144	)	
Interest rate	 	Derivatives liabilities—long-term	 	 	(68	)	 	(667	)	
​	​	​	​	​	​	​	​	​	​	
Total derivatives not designated as hedging instruments	 	 	 	$	251,696	 	$	(13,751	)	
​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	

(1)
Includes net deferred premiums payable of $1.8 million and zero related to commodity derivative contracts as of December 31, 2014 and 2013, respectively.

(2)
Includes net deferred premiums payable of $6.9 million and zero related to commodity derivative contracts as of December 31, 2014 and 2013, respectively.

(3)
Includes net deferred premiums payable of zero and $0.1 million related to commodity derivative contracts as of December 31, 2014 and 2013, respectively.

(4)
Includes net deferred premiums payable of zero and $6.5 million related to commodity derivative contracts as of December 31, 2014 and 2013, respectively.

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Notes to Consolidated Financial Statements (Continued)

9. Derivative Financial Instruments (Continued)

	 	 
	 	Amount of Gain/(Loss)	 	

	 	Years Ended December 31,	 	
Type of Contract	 	Location of Gain/(Loss)	 	2014	 	2013	 	2012	 	

	 	(In thousands)
	 	
Derivatives in cash flow hedging relationships:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest rate(1)	 	Interest expense	 	$	1,391	 	$	1,527	 	$	(163	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	
Total derivatives in cash flow hedging relationships	 	 	 	$	1,391	 	$	1,527	 	$	(163	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	
Derivatives not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity(2)	 	Oil and gas revenue	 	$	(11,661	)	$	(7,156	)	$	15,652	 	
Commodity	 	Derivatives, net	 	 	281,853	 	 	(17,027	)	 	(31,490	)	
Interest rate	 	Interest expense	 	 	(285	)	 	(437	)	 	(2,464	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	
Total derivatives not designated as hedging instruments	 	 	 	$	269,907	 	$	(24,620	)	$	(18,302	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	

(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, 2014 and 2013, 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, 2014 and 2013.

10. Fair Value Measurements

        In accordance with ASC 820—Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:

•
Level 1—quoted prices for identical assets or liabilities in active markets.

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

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Notes to Consolidated Financial Statements (Continued)

10. Fair Value Measurements (Continued)

•
Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

        The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2014 and 2013, for each fair value hierarchy level:

	 	Fair Value Measurements Using:	 	
 
	 	Quoted Prices in
Active Markets for
Identical Assets
(Level 1)	 	Significant Other
Observable Inputs
(Level 2)	 	Significant
Unobservable Inputs
(Level 3)	 	Total	 	
 
	 	(In thousands)
	 	
December 31, 2014	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	—	 	$	252,485	 	$	—	 	$	252,485	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	 	—	 	 	—	 	 	—	 	 	—	 	
Interest rate derivatives	 	 	—	 	 	(789	)	 	—	 	 	(789	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Total	 	$	—	 	$	251,696	 	$	—	 	$	251,696	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
December 31, 2013	 	 	 	 	 	 	 	 	 	 	 	 	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	—	 	$	(11,017	)	$	—	 	$	(11,017	)	
Interest rate derivatives	 	 	—	 	 	(2,734	)	 	—	 	 	(2,734	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Total	 	$	—	 	$	(13,751	)	$	—	 	$	(13,751	)	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
        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, purchased puts and swaps with calls 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 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 9—Derivative Financial Instruments for additional information regarding the Company's derivative instruments.

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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 subject to provisional pricing and (ii) an independently sourced forward curve over the term of the provisional pricing period.

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. The values attributable to the Company's interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.

Debt

        The following table presents the carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets:

	 	December 31, 2014	 	December 31, 2013	 	
 
	 	Carrying
Value	 	Fair
Value	 	Carrying
Value	 	Fair
Value	 	
 
	 	(In thousands)
	 	
Long-term debt	 	$	794,269	 	$	755,000	 	$	900,000	 	$	900,000	 	
        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 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 Company's asset retirement obligations:

	 	December 31,	 	
 
	 	2014	 	2013	 	
 
	 	(In thousands)
	 	
Asset retirement obligations:	 	 	 	 	 	 	 	
Beginning asset retirement obligations	 	$	39,596	 	$	27,484	 	
Liabilities incurred during period	 	 	—	 	 	8,558	 	
Revisions in estimated retirement obligations	 	 	—	 	 	—	 	
Accretion expense	 	 	4,427	 	 	3,554	 	
​	​	​	​	​	​	​	​	
Ending asset retirement obligations	 	$	44,023	 	$	39,596	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
        The Ghanaian legal and regulatory regime regarding oil field abandonment and other environmental matters is evolving. Currently, no Ghanaian environmental regulations expressly require that companies abandon or remove offshore assets. Under the Environmental Permit for the Jubilee Field, a decommissioning plan will be prepared and submitted to the Ghana Environmental Protection Agency. ASC 410—Asset Retirement and Environmental Obligations requires the Company to

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

11. Asset Retirement Obligations (Continued)

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, 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. The LTIP provides for the issuance of 24.5 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, 2014, the Company had approximately 2.1 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 $74.5 million, $69.0 million and $83.4 million during the years ended December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012 was $25.7 million, $23.5 million and $28.8 million, respectively. Additionally, we expensed a tax shortfall related to equity-based compensation of $6.5 million, $7.0 million and $8.1 million for the years ended December 31, 2014, 2013 and 2012, respectively. The fair value of awards vested during 2014, 2013 and 2012 was approximately $37.0 million, $41.1 million, and $75.7 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. These awards vest over a four year period. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.

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Notes to Consolidated Financial Statements (Continued)

12. Equity-based Compensation (Continued)

        The following table reflects the outstanding restricted stock awards as of December 31, 2014:

	 	Service Vesting
Restricted Stock
Awards	 	Weighted-
Average
Grant-Date
Fair Value	 	Market / Service
Vesting
Restricted Stock
Awards	 	Weighted-
Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)
	 	 
	 	(In thousands)

Outstanding at December 31, 2011	 	 	17,195	 	$	13.36	 	 	3,522	 	$	13.30	 	
Granted	 	 	590	 	 	12.05	 	 	303	 	 	9.45	 	
Forfeited	 	 	(994	)	 	13.87	 	 	(291	)	 	12.68	 	
Vested	 	 	(6,893	)	 	8.05	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Outstanding at December 31, 2012	 	 	9,898	 	 	16.92	 	 	3,534	 	 	12.93	 	
Granted	 	 	351	 	 	10.73	 	 	—	 	 	—	 	
Forfeited	 	 	(462	)	 	16.51	 	 	(96	)	 	12.35	 	
Vested	 	 	(3,403	)	 	17.18	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Outstanding at December 31, 2013	 	 	6,384	 	 	16.48	 	 	3,438	 	 	12.95	 	
Granted	 	 	—	 	 	—	 	 	—	 	 	—	 	
Forfeited	 	 	(122	)	 	15.20	 	 	(77	)	 	10.74	 	
Vested	 	 	(3,022	)	 	16.02	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Outstanding at December 31, 2014	 	 	3,240	 	 	16.95	 	 	3,361	 	 	13.00	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
        The following table reflects the outstanding restricted stock units as of December 31, 2014:

	 	Service Vesting
Restricted Stock
Units	 	Weighted-
Average
Grant-Date
Fair Value	 	Market / Service
Vesting
Restricted Stock
Units	 	Weighted-
Average
Grant-Date
Fair Value	 	
 
	 	(In thousands)
	 	 
	 	(In thousands)

Outstanding at December 31, 2011	 	 	—	 	$	—	 	 	—	 	$	—	 	
Granted	 	 	1,070	 	 	10.60	 	 	854	 	 	15.81	 	
Forfeited	 	 	(47	)	 	10.88	 	 	(29	)	 	15.81	 	
Vested	 	 	—	 	 	—	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Outstanding at December 31, 2012	 	 	1,023	 	 	10.59	 	 	825	 	 	15.81	 	
Granted	 	 	1,591	 	 	10.79	 	 	1,105	 	 	15.44	 	
Forfeited	 	 	(133	)	 	10.51	 	 	(72	)	 	15.74	 	
Vested	 	 	(243	)	 	10.59	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Outstanding at December 31, 2013	 	 	2,238	 	 	10.74	 	 	1,858	 	 	15.59	 	
Granted	 	 	2,113	 	 	10.80	 	 	1,572	 	 	15.71	 	
Forfeited	 	 	(412	)	 	10.90	 	 	(184	)	 	15.48	 	
Vested	 	 	(572	)	 	10.74	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
Outstanding at December 31, 2014	 	 	3,367	 	 	10.76	 	 	3,246	 	 	15.66	 	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	​	​	​	
        As of December 31, 2014, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $80.2 million over a weighted average period of 1.61 years.

        For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company's total shareholder return with the total shareholder return of a predetermined group of peer companies

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Notes to Consolidated Financial Statements (Continued)

12. Equity-based Compensation (Continued)

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 $15.44 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 39.0% 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.

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.

        The components of income before income taxes were as follows:

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands)
	 	
Bermuda	 	$	(31,787	)	$	(26,492	)	$	(11,651	)	
United States	 	 	15,684	 	 	11,872	 	 	14,342	 	
Foreign—other	 	 	594,371	 	 	90,574	 	 	31,465	 	
​	​	​	​	​	​	​	​	​	​	​	
Income before income taxes	 	$	578,268	 	$	75,954	 	$	34,156	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

13. Income Taxes (Continued)

        The components of the provision for income taxes attributable to our income before income taxes consist of the following:

	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands)
	 	
Current:	 	 	 	 	 	 	 	 	 	 	
Bermuda	 	$	—	 	$	—	 	$	—	 	
United States	 	 	27,167	 	 	14,182	 	 	21,148	 	
Foreign—other	 	 	55,322	 	 	70,436	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Total current	 	 	82,489	 	 	84,618	 	 	21,148	 	
Deferred:	 	 	 	 	 	 	 	 	 	 	
Bermuda	 	 	—	 	 	—	 	 	—	 	
United States	 	 	(14,403	)	 	(2,665	)	 	(7,908	)	
Foreign—other	 	 	230,812	 	 	85,045	 	 	87,944	 	
​	​	​	​	​	​	​	​	​	​	​	
Total deferred	 	 	216,409	 	 	82,380	 	 	80,036	 	
​	​	​	​	​	​	​	​	​	​	​	
Income tax expense	 	$	298,898	 	$	166,998	 	$	101,184	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
        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,	 	
 
	 	2014	 	2013	 	2012	 	
 
	 	(In thousands)
	 	
Tax at Bermuda statutory rate	 	$	—	 	$	—	 	$	—	 	
Foreign income taxed at different rates	 	 	266,993	 	 	127,301	 	 	73,277	 	
Change in valuation allowance(1)	 	 	16,401	 	 	(4,065	)	 	14,103	 	
Non-deductible and other items(1)	 	 	8,957	 	 	36,664	 	 	5,669	 	
Tax shortfall on equity-based compensation	 	 	6,547	 	 	7,098	 	 	8,135	 	
​	​	​	​	​	​	​	​	​	​	​	
Total tax expense	 	$	298,898	 	$	166,998	 	$	101,184	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Effective tax rate(2)	 	 	51.7	%	 	219.9	%	 	296.2	%	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	

(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, 2014, 2013 and 2012 was also impacted by losses of $159.9 million, $178.8 million and $168.5 million, respectively, incurred in jurisdictions in which we are not subject to taxes and, therefore, do not generate any income tax benefits.

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Notes to Consolidated Financial Statements (Continued)

13. Income Taxes (Continued)

        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 81%, 97% and 92% for the years ended December 31, 2014, 2013 and 2012, 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 36% for the years ended December 31, 2014, 2013 and 2012. 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.

        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 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,	 	
 
	 	2014	 	2013	 	
 
	 	(In thousands)
	 	
Deferred tax assets:	 	 	 	 	 	 	 	
Foreign capitalized operating expenses(1)	 	$	60,401	 	$	46,087	 	
Foreign net operating losses(1)	 	 	15,548	 	 	17,579	 	
Equity compensation	 	 	36,711	 	 	28,112	 	
Unrealized derivative losses	 	 	—	 	 	10,197	 	
Other	 	 	20,657	 	 	9,582	 	
​	​	​	​	​	​	​	​	
Total deferred tax assets	 	 	133,317	 	 	111,557	 	
Valuation allowance(1)	 	 	(75,941	)	 	(59,540	)	
​	​	​	​	​	​	​	​	
Total deferred tax assets, net	 	 	57,376	 	 	52,017	 	
Deferred tax liabilities:	 	 	 	 	 	 	 	
Depletion, depreciation and amortization related to property and equipment	 	 	(322,895	)	 	(186,333	)	
Unrealized derivative gains	 	 	(92,675	)	 	—	 	
​	​	​	​	​	​	​	​	
Total deferred tax liabilities	 	 	(415,570	)	 	(186,333	)	
​	​	​	​	​	​	​	​	
Net deferred tax asset (liability)	 	$	(358,194	)	$	(134,316	)	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	

(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.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

13. Income Taxes (Continued)

        The Company has recorded a full valuation allowance against the net deferred tax assets in Ireland, Mauritania, Morocco, Senegal and Suriname. The net change in the valuation allowance of $16.4 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 $28.9 million, recorded at the Moroccan statutory rate of 30%, with an offsetting valuation allowance of $28.9 million. 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 $52.4 million. Of these losses, we expect $0.8 million, $9.4 million, $35.5 million and $0.6 million to expire in 2014, 2015, 2016 and 2021, 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 2014 and to Texas margin tax examinations for the tax years 2010 through 2014. In addition, the Company is open to income tax examinations for years 2004 through 2014 in its significant other foreign jurisdictions (Ghana, Cameroon and Morocco).

        As of December 31, 2014, the Company had no material uncertain tax positions. The Company's policy is to recognize potential interest and penalties related to income tax matters in income tax expense, but has had no need to accrue any to date.

14. Net Income (Loss) Per Share

        In the calculation of basic net income per common share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. We calculate basic net income per common share attributable to common shareholders under the two-class method. The Company's participating securities, which consist solely of service vesting restricted stock awards (See Note 12—Equity-based Compensation), do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income (loss) per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or 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 attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed not to occur. Diluted net income (loss) per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented.

        Basic net income (loss) per share attributable to common shareholders is computed as (i) net income (loss) attributable to common shareholders, (ii) less income allocable to participating securities

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

14. Net Income (Loss) Per Share (Continued)

(iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common shareholders is computed as (i) basic net income (loss) attributable to common shareholders, (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding.

	 	Year Ended December 31,	 	
(In thousands, except per share data)	 	2014	 	2013	 	2012	 	
Numerator:	 	 	 	 	 	 	 	 	 	 	
Net income (loss) attributable to common shareholders	 	$	279,370	 	$	(91,044	)	$	(67,028	)	
Less: Basic income allocable to participating securities(1)	 	 	3,286	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Basic net income (loss) allocable to common shareholders	 	 	276,084	 	 	(91,044	)	 	(67,028	)	
Diluted adjustments to income allocable to participating securities(1)	 	 	58	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Diluted net income (loss) allocable to common shareholders	 	$	276,142	 	$	(91,044	)	$	(67,028	)	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Denominator:	 	 	 	 	 	 	 	 	 	 	
Weighted average number of shares used to compute net income (loss) per share:	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	379,195	 	 	376,819	 	 	371,847	 	
Restricted stock awards and units(1)(2)	 	 	6,924	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Diluted	 	 	386,119	 	 	376,819	 	 	371,847	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Net income (loss) per share attributable to common shareholders:	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	0.73	 	$	(0.24	)	$	(0.18	)	
Diluted	 	$	0.72	 	$	(0.24	)	$	(0.18	)	

(1)
Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per common share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses 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, 2014, 2013 and 2012, we excluded 4.4 million, 13.9 million and 15.3 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

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements (Continued)

15. Commitments and Contingencies (Continued)

upon the Company's financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.

        The Jubilee Field in Ghana covers an area within both the WCTP and DT petroleum contract areas. Consistent with the Ghanaian Petroleum Law, the WCTP and DT petroleum contracts and as required by Ghana's Ministry of Energy, it was agreed the Jubilee Field would be unitized for optimal resource recovery. Kosmos and its partners executed a comprehensive unit operating agreement, the Jubilee UUOA, to unitize the Jubilee Field and govern each party's respective rights and duties in the Jubilee Unit, which was effective July 16, 2009. Pursuant to the terms of the Jubilee UUOA, the tract participations are subject to a process of redetermination. The initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process, our Unit Interest is 24.1%. These consolidated financial statements are based on these re-determined tract participations. Our unit interest may change in the future should another redetermination occur.

        The Company leases facilities under various operating leases that expire through 2019, including our office space. Rent expense under these agreements was $4.6 million, $4.1 million and $4.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

        In June 2013, we signed a long-term rig agreement with a subsidiary of Atwood Oceanics, Inc. for the new build 6th generation drillship "Atwood Achiever."

        We took delivery of the Atwood Achiever in September 2014. The rig agreement covers 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. We have entered into a rig sharing agreement, whereby two rig slots (estimated to be 130 days during 2015 and 30 days during 2016) were assigned to a third-party.

        Future minimum rental commitments under these leases at December 31, 2014, are as follows:

	 	Payments Due By Year(1)	 	
 
	 	Total	 	2015	 	2016	 	2017	 	2018	 	2019	 	Thereafter	 	
 
	 	(In thousands)
	 	
Operating leases	 	$	16,095	 	$	3,260	 	$	3,158	 	$	3,223	 	$	3,323	 	$	3,131	 	$	—	 	
Atwood Achiever drilling rig contract(2)	 	$	486,115	 	$	139,825	 	$	199,920	 	$	146,370	 	$	—	 	$	—	 	$	—	 	

(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)
Commitments calculated using a day rate of $595,000, excluding applicable taxes. The rig commitments reflect the execution of a rig sharing agreement, whereby two rig slots (estimated to be 130 days during 2015 and 30 days during 2016) were assigned to a third party.

16. Subsequent Events

January 2015 LTIP Grant

        In January 2015, we granted 1.7 million service vesting restricted stock awards and restricted stock units and 3.3 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately $46.8 million of non-cash compensation expense related to these grants over the next 3 years.

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KOSMOS ENERGY LTD.

Supplemental Oil and Gas Data (Unaudited)

        Net proved oil and gas reserve estimates presented were prepared by Ryder Scott Company, L.P. ("RSC") for the year ended December 31, 2014 and Netherland, Sewell & Associates, Inc. ("NSAI") for the years ended December 31, 2013 and 2012. 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, 2011(1)	 	 	47	 	 	24	 	 	51	 	
Extensions and discoveries	 	 	—	 	 	—	 	 	—	 	
Production	 	 	(6	)	 	(1	)	 	(6	)	
Revision in estimate(2)	 	 	1	 	 	(14	)	 	(2	)	
Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Net proved developed and undeveloped reserves at December 31, 2012(1)	 	 	
42	 	 	
9	 	 	
43	 	
Extensions and discoveries	 	 	—	 	 	—	 	 	—	 	
Production	 	 	(8	)	 	(1	)	 	(8	)	
Revision in estimate(3)	 	 	11	 	 	3	 	 	12	 	
Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Net proved developed and undeveloped reserves at December 31, 2013(1)	 	 	45	 	 	11	 	 	47	 	
Extensions and discoveries(4)	 	 	26	 	 	6	 	 	27	 	
Production	 	 	(9	)	 	(1	)	 	(9	)	
Revision in estimate(5)	 	 	11	 	 	(2	)	 	10	 	
Purchases of minerals-in-place	 	 	—	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Net proved developed and undeveloped reserves at December 31, 2014(1)	 	 	73	 	 	14	 	 	75	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Proved developed reserves(1)	 	 	 	 	 	 	 	 	 	 	
December 31, 2012	 	 	32	 	 	9	 	 	33	 	
December 31, 2013	 	 	36	 	 	10	 	 	38	 	
December 31, 2014	 	 	43	 	 	9	 	 	45	 	
Proved undeveloped reserves(1)	 	 	 	 	 	 	 	 	 	 	
December 31, 2012	 	 	10	 	 	1	 	 	10	 	
December 31, 2013	 	 	9	 	 	1	 	 	9	 	
December 31, 2014	 	 	30	 	 	6	 	 	31	 	

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

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(2)
The estimated decrease in gas reserves represents a decrease in estimated gas reserves to be utilized as fuel gas for the Jubilee Field FPSO.

(3)
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.

(4)
Discoveries are related to the TEN development being moved from unproved to proved during 2014.

(5)
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.

        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 2014. The average 2014 Brent crude price of $101.30 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 an additional $0.25 per barrel; therefore, the adjusted oil price is $101.55 per barrel. This oil price is held constant throughout the lives of the properties. There is no gas price used because gas reserves are consumed in operations as fuel.

        Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S-X as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered under current economic conditions, operating methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.

Capitalized Costs Related to Oil and Gas Activities

        The following table presents aggregate capitalized costs related to oil and gas activities:

	 	Ghana	 	Other(1)	 	Total	 	
 
	 	(In thousands)
	 	
As of December 31, 2014	 	 	 	 	 	 	 	 	 	 	
Unproved properties	 	$	252,051	 	$	111,666	 	$	363,717	 	
Proved properties	 	 	2,125,590	 	 	—	 	 	2,125,590	 	
​	​	​	​	​	​	​	​	​	​	​	
 	 	 	2,377,641	 	 	111,666	 	 	2,489,307	 	
Accumulated depletion, depreciation and amortization	 	 	(716,121	)	 	—	 	 	(716,121	)	
​	​	​	​	​	​	​	​	​	​	​	
Net capitalized costs	 	$	1,661,520	 	$	111,666	 	$	1,773,186	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
As of December 31, 2013	 	 	 	 	 	 	 	 	 	 	
Unproved properties	 	$	492,065	 	$	32,192	 	$	524,257	 	
Proved properties	 	 	1,511,637	 	 	—	 	 	1,511,637	 	
​	​	​	​	​	​	​	​	​	​	​	
 	 	 	2,003,702	 	 	32,192	 	 	2,035,894	 	
Accumulated depletion, depreciation and amortization	 	 	(527,832	)	 	—	 	 	(527,832	)	
​	​	​	​	​	​	​	​	​	​	​	
Net capitalized costs	 	$	1,475,870	 	$	32,192	 	$	1,508,062	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	

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

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Costs Incurred in Oil and Gas Activities

        The following table reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration, and development activities for the year.

	 	Ghana	 	Other(1)	 	Total	 	
 
	 	(In thousands)
	 	
Year ended December 31, 2014	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	—	 	$	—	 	$	—	 	
Proved	 	 	—	 	 	—	 	 	—	 	
Exploration(3)	 	 	62,813	 	 	167,381	 	 	230,194	 	
Development	 	 	316,738	 	 	—	 	 	316,738	 	
​	​	​	​	​	​	​	​	​	​	​	
Total costs incurred	 	$	379,551	 	$	167,381	 	$	546,932	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Year ended December 31, 2013	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	—	 	$	13,787	 	$	13,787	 	
Proved	 	 	—	 	 	—	 	 	—	 	
Exploration(2)	 	 	61,071	 	 	183,213	 	 	244,284	 	
Development(2)	 	 	183,635	 	 	—	 	 	183,635	 	
​	​	​	​	​	​	​	​	​	​	​	
Total costs incurred	 	$	244,706	 	$	197,000	 	$	441,706	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
Year ended December 31, 2012	 	 	 	 	 	 	 	 	 	 	
Property acquisition:	 	 	 	 	 	 	 	 	 	 	
Unproved	 	$	—	 	$	5,000	 	$	5,000	 	
Proved	 	 	—	 	 	—	 	 	—	 	
Exploration	 	 	173,463	 	 	81,879	 	 	255,342	 	
Development	 	 	161,925	 	 	—	 	 	161,925	 	
​	​	​	​	​	​	​	​	​	​	​	
Total costs incurred	 	$	335,388	 	$	86,879	 	$	422,267	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	

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

(2)
The exploration and development costs incurred in Ghana as reported in our prior year annual report on Form 10-K were $183.6 million and $61.1 million, respectively. The table above has been revised to properly present the amounts.

(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 the current year.

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 2014. The average 2014 Brent crude price of $101.30 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 an additional $0.25 per barrel for the Jubilee Field; therefore, the adjusted oil price is $101.55 per barrel for Jubilee. TEN was not adjusted as it does not currently have any production. 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.

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        The projection should not be interpreted as representing the current value to Kosmos. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Kosmos' investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions.

        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, 2014	 	 	 	 	
Future cash inflows	 	$	7,412	 	
Future production costs	 	 	(1,466	)	
Future development costs	 	 	(1,051	)	
Future Ghanaian tax expenses(1)	 	 	(1,543	)	
​	​	​	​	​	
Future net cash flows	 	 	3,352	 	
10% annual discount for estimated timing of cash flows	 	 	(969	)	
​	​	​	​	​	
Standardized measure of discounted future net cash flows	 	$	2,383	 	
​	​	​	​	​	
​	​	​	​	​	
​	​	​	​	​	
At December 31, 2013	 	 	 	 	
Future cash inflows	 	$	4,921	 	
Future production costs	 	 	(617	)	
Future development costs	 	 	(300	)	
Future Ghanaian tax expenses(1)	 	 	(1,168	)	
​	​	​	​	​	
Future net cash flows	 	 	2,836	 	
10% annual discount for estimated timing of cash flows	 	 	(599	)	
​	​	​	​	​	
Standardized measure of discounted future net cash flows	 	$	2,237	 	
​	​	​	​	​	
​	​	​	​	​	
​	​	​	​	​	
At December 31, 2012	 	 	 	 	
Future cash inflows	 	$	4,708	 	
Future production costs	 	 	(599	)	
Future development costs	 	 	(429	)	
Future Ghanaian tax expenses(1)	 	 	(1,068	)	
​	​	​	​	​	
Future net cash flows	 	 	2,612	 	
10% annual discount for estimated timing of cash flows	 	 	(540	)	
​	​	​	​	​	
Standardized measure of discounted future net cash flows	 	$	2,072	 	
​	​	​	​	​	
​	​	​	​	​	
​	​	​	​	​	

(1)
Standardized Measure includes the effects of both future income tax expense related to the Company's proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level on future net revenues and future tax expense levied at an asset level (in the Company's case, future Ghanaian tax expense levied under the WCTP and DT petroleum contracts). As the Company has been a tax exempted company incorporated pursuant to the laws of the Cayman Islands to date and is now a tax exempted company incorporated pursuant to the laws of Bermuda since the completion of the corporate reorganization, and as the Company's intermediate subsidiaries positioned between it and the subsidiary that is a signatory to the WCTP and DT petroleum contracts will continue to be tax exempted companies, the Company has not been and does not expect to be

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subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent or intermediate subsidiary level. Accordingly, the Company's Standardized Measure for the years ended December 31, 2014, 2013 and 2012, respectively, only reflect the effects of future Ghanaian tax expense levied under the WCTP and DT petroleum contracts.

Changes in the Standardized Measure for Discounted Cash Flows

	 	Ghana	 	
 
	 	(In millions)
	 	
Balance at December 31, 2011	 	$	2,016	 	
Sales and Transfers 2012	 	 	(573	)	
Net changes in prices and costs	 	 	32	 	
Previously estimated development costs incurred during the period	 	 	158	 	
Net changes in development costs	 	 	122	 	
Revisions of previous quantity estimates	 	 	49	 	
Net changes in Ghanaian tax expenses(1)	 	 	(105	)	
Accretion of discount	 	 	274	 	
Changes in timing and other	 	 	99	 	
​	​	​	​	​	
Balance at December 31, 2012	 	$	2,072	 	
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 expenses(1)	 	 	(32	)	
Accretion of discount	 	 	289	 	
Changes in timing and other	 	 	(182	)	
​	​	​	​	​	
Balance at December 31, 2013	 	$	2,237	 	
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 expenses(1)	 	 	(44	)	
Accretion of discount	 	 	306	 	
Changes in timing and other	 	 	(174	)	
​	​	​	​	​	
Balance at December 31, 2014	 	$	2,383	 	
​	​	​	​	​	
​	​	​	​	​	
​	​	​	​	​	

(1)
Standardized Measure includes the effects of both future income tax expense related to the Company's proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level on future net revenues and future tax expense levied at an asset level (in the Company's case, future Ghanaian tax expense levied under the WCTP and DT petroleum contracts). As the Company has been a tax exempted company incorporated pursuant to the laws of the Cayman Islands to date and is now a tax exempted company incorporated pursuant to the laws of Bermuda since the completion of the corporate reorganization, and as the Company's intermediate subsidiaries positioned between it and the subsidiary that is a signatory to the WCTP and DT petroleum contracts will continue

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to be tax exempted companies, 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 or intermediate subsidiary level. Accordingly, the Company's Standardized Measure for the years ended December 31, 2014, 2013 and 2012, respectively, only reflect the effects of future Ghanaian tax expense levied under the WCTP and DT petroleum contracts.

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KOSMOS ENERGY LTD.

Supplemental Quarterly Financial Information (Unaudited)

 
	 	Quarter Ended	 	
 
	 	March 31,	 	June 30,	 	September 30,	 	December 31,	 	
 
	 	(In thousands, except per share data)
	 	
2014	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues	 	$	237,061	 	$	329,166	 	$	138,367	 	$	178,144	 	
Expenses	 	 	111,309	 	 	191,875	 	 	80,776	 	 	(79,490	)	
Net income	 	 	74,969	 	 	56,507	 	 	19,123	 	 	128,771	 	
Net income attributable to common shareholders	 	 	74,969	 	 	56,507	 	 	19,123	 	 	128,771	 	
Net income attributable to common shareholders per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic(1)	 	 	0.20	 	 	0.15	 	 	0.05	 	 	0.34	 	
Diluted(1)	 	 	0.19	 	 	0.15	 	 	0.05	 	 	0.33	 	
2013	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues	 	$	228,390	 	$	193,778	 	$	215,379	 	$	214,881	 	
Expenses	 	 	164,205	 	 	218,341	 	 	225,643	 	 	168,285	 	
Net income (loss)	 	 	20,094	 	 	(70,816	)	 	(44,488	)	 	4,166	 	
Net income (loss) attributable to common shareholders	 	 	20,094	 	 	(70,816	)	 	(44,488	)	 	4,166	 	
Net income (loss) attributable to common shareholders per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic(1)	 	 	0.05	 	 	(0.19	)	 	(0.12	)	 	0.01	 	
Diluted(1)	 	 	0.05	 	 	(0.19	)	 	(0.12	)	 	0.01	 	

(1)
The sum of the quarterly earnings per share information may not add to the annual earnings per share information due to rounding.

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Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) was performed under the supervision and with the participation of the Company's management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective as of December 31, 2014, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

        There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Annual Report on Internal Control over Financial Reporting

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control has been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. All internal control systems have inherent limitations, including the possibility of human error and the possible circumvention of or overriding of controls. The design of an internal control system is also based in part upon assumptions and judgments made by management. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        Under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this report based on the framework in "Internal Control—Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to

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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, 2014 which is included in "Item 8. Financial Statements and Supplementary Data."

Item 9B.    Other Information

Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934

        Under the Iran Threat Reduction and Syria Human Rights Act of 2012, which added Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our "affiliates" (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the Securities and Exchange Commission ("SEC") defines the term "affiliate" broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us ("control" is also construed broadly by the SEC).

        We are not presently aware that we and our consolidated subsidiaries have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the fiscal quarter ended December 31, 2014. In addition, except as described below, at the time of filing this anuual 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, 2014, as the case may be, additional reportable transactions may be disclosed by such companies.

        As of December 31, 2014, 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, 2014.

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 "EIG Disclosure") regarding the Endurance International Group ("EIG"). Each of SAMIH and EIG are companies that may be considered affiliates of Warburg Pincus. Because we, SAMIH, and EIG may be deemed to be controlled by Warburg Pincus, we may be considered an "affiliate" of each of SAMIH and EIG, respectively, for the purposes of Section 13(r) of the Exchange Act.

SAMIH Disclosure:

Quarter ended December 31, 2014

"Santander UK holds frozen savings and current accounts for three customers resident in the U.K. who are currently designated by the U.S. for terrorism. The accounts held by each customer were blocked after the customer's designation and remained blocked and dormant throughout 2014. No

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revenue has been generated by Santander UK on these accounts. The bank account held for one of these customers was closed in the fourth quarter of 2014.

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 sanctions program"), holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made (or would be permitted) under this mortgage although Santander UK continues to receive repayment installments. In 2014, total revenue in connection with the mortgage was approximately £2,580 and net profits were negligible relative to the overall profits of Santander UK. The same Iranian national also holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen during 2014. 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 £250 and net profits in 2014 were negligible relative to the overall profits of Banco Santander, S.A.

In addition, during the third quarter 2014, Santander UK identified two additional customers: a UK national designated by the U.S. under the NPWMD sanctions program held a business account. No transactions were made and the account was closed in the fourth quarter of 2014. No revenue or profit has been generated. A second UK national designated by the US for reasons of terrorism held a personal current account and a personal credit card account, both of which were closed in the third quarter of 2014. Although transactions took place on the current account during the third quarter of 2014, revenue and profits generated were negligible. No transactions took place on the credit card."

        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.

EIG Disclosure:

Quarter ended December 31, 2014

"On July 2, 2013, the billing information for a subscriber account (the "Subscriber Account") was updated to include Seyed Mahmoud Mohaddes ("Mohaddes"). On September 16, 2013, the Office of Foreign Assets Control ("OFAC"), designated Mohaddes as a Specially Designated National ("SDN"), pursuant to 31 C.F.R. Part 560.304. On or around September 26, 2014, during a routine compliance scan of new and existing subscriber accounts, EIG discovered that Mohaddes, a SDN, was named as an account contact for the Subscriber Account. EIG promptly suspended the Subscriber Account, locked the domain name IOCUKLTD.COM, which was registered to the Subscriber Account, and reported the domain name to OFAC as potentially the property of a SDN subject to blocking pursuant to Executive Order 13599. Since September 16, 2013, when Mohaddes was added to the SDN list, charges in the total amount of $120.35 were made to the Subscriber Account for web hosting and domain privacy services. EIG has ceased billing for the Subscriber Account. To date, EIG has not received any correspondence from OFAC regarding this matter.

On July 10, 2014, OFAC designated each of Stars Group Holding ("Stars"), and Teleserve Plus SAL ("Teleserve"), as SDNs under Executive Order 13224, and their property became subject to blocking pursuant to the Global Terrorism Sanctions Regulations, 31 C.F.R. Part 594. On July 15, 2014, as part of EIG's compliance review processes, EIG discovered that the domain names

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associated with each of Stars, STARSCOM.NET, and Teleserve, TELESERVEPLUS.COM (collectively, the "Stars/Teleserve Domain Names"), were registered through EIG's platform. EIG immediately took steps to suspend and lock the Stars/Teleserve Domain Names to prevent them from being transferred or resolving to a website, and EIG promptly reported the Domain Names as potentially blocked property to OFAC. EIG did not generate any revenue from the Stars/Teleserve Domain Names between when they were added to the SDN list on July 10, 2014 and when EIG discovered that they were registered through EIG's platform on July 15, 2014. To date, EIG has not received any correspondence from OFAC regarding the matter.

On July 15, 2014 during a compliance scan of all domain names on one of our platforms, EIG identified the domain name KAHANETZADAK.COM ("the Domain Name"), which was listed as an 'also known as,' or AKA, of the entity Kahane Chai which operates as the American Friends of the United Yeshiva. Kahane Chai was designated as a SDN on November 2, 2001 pursuant to Executive Order 13224. Because the Domain Name was transferred into a customer account of one of EIG's resellers, there was no direct financial transaction between EIG and the registered owner of the Domain Name. The Domain Name was suspended upon EIG's discovering it on EIG's platform, and EIG reported the Domain Name to OFAC as potentially the property of a SDN. To date, EIG have not received any correspondence from OFAC regarding the matter."

        The EIG Disclosure relates solely to activities conducted by EIG and do not relate to any activities conducted by us. We have no involvement in or control over the activities of EIG , any of its predecessor companies or any of its subsidiaries. Other than as described above, we have no knowledge of the activities of EIG with respect to transactions with Iran, and we have not participated in the preparation of the EIG Disclosure. We have not independently verified the EIG Disclosure, are not representing to the accuracy or completeness of the EIG Disclosure and undertake no obligation to correct or update the EIG Disclosure.

Disclosure relating to Blackstone and its affiliates

        Blackstone informed us of the information reproduced below (the "Travelport Disclosure") regarding Travelport Limited ("Travelport"), a company that may be considered one of Blackstone's affiliates. Because both we and Travelport may be deemed to be controlled by Blackstone, we may be considered an "affiliate" of Travelport for the purposes of Section 13(r) of the Exchange Act.

Travelport Disclosure:

Quarter ended December 31, 2014

"As part of our global business in the travel industry, we provide certain passenger travel-related GDS 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 exempt/licensed status of such activities, we intend to continue these business activities, which are directly related to and promote the arrangement of travel for individuals."

        Travelport has not provided Blackstone with gross revenues and net profits attributable to the activities described above.

        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.

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PART III

Item 10.    Directors, Executive Officers and Corporate Governance

        The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

Item 11.    Executive Compensation

        The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

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 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

        The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

Item 14.    Principal Accounting Fees and Services

        The information required by this item is incorporated herein by reference to the 2014 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2014.

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PART IV

Item 15.    Exhibits, Financial Statement Schedules

        (a)   The following documents are filed as part of this report:

(1)   Financial statements

        The financial statements filed as part of the Annual Report on Form 10-K are listed in the accompanying index to consolidated financial statements in Item 8, Financial Statements and Supplementary Data.

(2)   Financial statement schedules

Schedule I—Condensed Parent Company Financial Statements

        Under the terms of agreements governing the indebtedness of subsidiaries of Kosmos Energy Ltd. for 2014, 2013 and 2012 (collectively "KEL," the "Parent Company"), such subsidiaries are restricted from making dividend payments, loans or advances to KEL. Schedule I of Article 5-04 of Regulation S-X requires the condensed financial information of the Parent Company to be filed when the restricted net assets of consolidated subsidiaries exceed 25 percent of consolidated net assets as of the end of the most recently completed fiscal year.

        The following condensed parent-only financial statements of KEL have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X and included herein. The Parent Company's 100% investment in its subsidiaries has been recorded using the equity basis of accounting in the accompanying condensed parent-only financial statements. The condensed financial statements should be read in conjunction with the consolidated financial statements of Kosmos Energy Ltd. and subsidiaries and notes thereto.

        The terms "Kosmos," the "Company," and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise. Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or shareholders equity.

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KOSMOS ENERGY LTD.

CONDENSED PARENT COMPANY BALANCE SHEETS

(In thousands, except share data)

 
	 	December 31,	 	
 
	 	2014	 	2013	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	165,894	 	$	35,092	 	
Receivables from subsidiaries	 	 	154	 	 	—	 	
Prepaid expenses and other	 	 	435	 	 	524	 	
​	​	​	​	​	​	​	​	
Total current assets	 	 	166,483	 	 	35,616	 	
Investment in subsidiaries at equity	 	 	1,474,105	 	 	955,460	 	
Deferred financing costs, net of accumulated amortization of $6,488 and $3,300, respectively	 	 	4,163	 	 	5,950	 	
​	​	​	​	​	​	​	​	
Total assets	 	$	1,644,751	 	$	997,026	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
Liabilities and shareholders' equity	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
Accounts payable	 	$	—	 	$	35	 	
Accounts payable to subsidiaries	 	 	—	 	 	3,761	 	
Accrued liabilities	 	 	11,523	 	 	895	 	
​	​	​	​	​	​	​	​	
Total current liabilities	 	 	11,523	 	 	4,691	 	
Long-term debt	 	 	294,269	 	 	—	 	
Shareholders' equity:	 	 	

Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2014 and 2013	 	 	—	 	 	—	 	
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 392,443,048 and 391,974,287 issued at December 31, 2014 and 2013, respectively	 	 	3,924	 	 	3,920	 	
Additional paid-in capital	 	 	1,860,190	 	 	1,781,535	 	
Accumulated deficit	 	 	(494,850	)	 	(774,220	)	
Accumulated other comprehensive income	 	 	767	 	 	2,158	 	
Treasury stock, at cost, 5,555,088 and 4,400,135 shares at December 31, 2014 and 2013, respectively	 	 	(31,072	)	 	(21,058	)	
​	​	​	​	​	​	​	​	
Total shareholders' equity	 	 	1,338,959	 	 	992,335	 	
​	​	​	​	​	​	​	​	
Total liabilities and shareholders' equity	 	$	1,644,751	 	$	997,026	 	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	
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KOSMOS ENERGY LTD.

CONDENSED PARENT COMPANY STATEMENTS OF OPERATIONS

(In thousands)

 
	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	—	 	$	—	 	$	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Total revenues and other income	 	 	—	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
General and administrative	 	 	88,789	 	 	84,306	 	 	93,472	 	
General and administrative recoveries—related party	 	 	(78,880	)	 	(67,865	)	 	(82,370	)	
Interest and other financing costs, net	 	 	20,559	 	 	9,997	 	 	542	 	
Other expenses, net	 	 	1,319	 	 	54	 	 	6	 	
Equity in (earnings) losses of subsidiaries	 	 	(311,157	)	 	64,552	 	 	55,378	 	
​	​	​	​	​	​	​	​	​	​	​	
Total costs and expenses	 	 	(279,370	)	 	91,044	 	 	67,028	 	
​	​	​	​	​	​	​	​	​	​	​	
Income (loss) before income taxes	 	 	279,370	 	 	(91,044	)	 	(67,028	)	
Income tax expense	 	 	—	 	 	—	 	 	—	 	
​	​	​	​	​	​	​	​	​	​	​	
Net income (loss)	 	$	279,370	 	$	(91,044	)	$	(67,028	)	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
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KOSMOS ENERGY LTD.

CONDENSED PARENT COMPANY STATEMENTS OF CASH FLOWS

(In thousands)

 
	 	Years Ended December 31,	 	
 
	 	2014	 	2013	 	2012	 	
Operating activities	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	279,370	 	$	(91,044	)	$	(67,028	)	
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	
Equity in (earnings) losses of subsidiaries	 	 	(311,157	)	 	64,552	 	 	55,378	 	
Equity-based compensation	 	 	79,741	 	 	69,101	 	 	83,423	 	
Amortization	 	 	3,188	 	 	3,017	 	 	283	 	
Other	 	 	269	 	 	—	 	 	—	 	
Changes in assets and liabilities:	 	 	 	 	 	 	 	 	 	 	
(Increase) decrease in prepaid expenses and other	 	 	89	 	 	(149	)	 	19	 	
(Increase) decrease due to/from related party	 	 	(3,915	)	 	4,134	 	 	(1,531	)	
Increase in accounts payable and accrued liabilities	 	 	10,593	 	 	794	 	 	136	 	
​	​	​	​	​	​	​	​	​	​	​	
Net cash provided by operating activities	 	 	58,178	 	 	50,405	 	 	70,680	 	
Investing activities	 	 	

 	 	
Investment in subsidiaries	 	 	(208,879	)	 	(133,066	)	 	(275,070	)	
​	​	​	​	​	​	​	​	​	​	​	
Net cash used in investing activities	 	 	(208,879	)	 	(133,066	)	 	(275,070	)	
Financing activities	 	 	

 	 	
Net proceeds from issuance of senior secured notes	 	 	294,000	 	 	—	 	 	—	 	
Purchase of treasury stock	 	 	(11,096	)	 	(13,101	)	 	(8,378	)	
Deferred financing costs	 	 	(1,401	)	 	(1,720	)	 	(7,530	)	
​	​	​	​	​	​	​	​	​	​	​	
Net cash provided by (used in) financing activities	 	 	281,503	 	 	(14,821	)	 	(15,908	)	
​	​	​	​	​	​	​	​	​	​	​	
Net increase (decrease) in cash and cash equivalents	 	 	
130,802	 	 	
(97,482	
)	 	
(220,298	
)	
Cash and cash equivalents at beginning of period	 	 	35,092	 	 	132,574	 	 	352,872	 	
​	​	​	​	​	​	​	​	​	​	​	
Cash and cash equivalents at end of period	 	$	165,894	 	$	35,092	 	$	132,574	 	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
​	​	​	​	​	​	​	​	​	​	​	
151

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Schedule II

Kosmos Energy Ltd.

Valuation and Qualifying Accounts

For the Years Ended December 31, 2014, 2013 and 2012

 
	 	 
	 	Additions	 	 

Description	 	Balance
January 1,	 	Charged to
Costs and
Expenses	 	Charged
To Other
Accounts	 	Deductions
From
Reserves	 	Balance
December 31,	 	
2014	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful receivables	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	
Allowance for deferred tax asset	 	$	59,540	 	$	16,401	 	$	—	 	$	—	 	$	75,941	 	
2013	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful receivables	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	
Allowance for deferred tax asset	 	$	63,605	 	$	28,040	 	$	—	 	$	32,105	 	$	59,540	 	
2012	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful receivables	 	$	—	 	$	—	 	$	—	 	$	—	 	$	—	 	
Allowance for deferred tax asset	 	$	49,502	 	$	14,103	 	$	—	 	$	—	 	$	63,605	 	
        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 155 for a description of the exhibits filed as part of this report.

152

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SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 	 	 	 	 	
 	 	KOSMOS ENERGY LTD.	

Date: February 23, 2015	
 	
By:	
 	
/s/ THOMAS P. CHAMBERS

Thomas P. Chambers
Senior Vice President and Chief Financial Officer	
        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
 	 	 	 	 	
Signature	 	Title	 	Date	

 	

 	
/s/ ANDREW G. INGLIS

Andrew G. Inglis	 	Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)	 	February 23, 2015	

/s/ BRIAN F. MAXTED

Brian F. Maxted	
 	
Director and Chief Exploration Officer	
 	
February 23, 2015	

/s/ THOMAS P. CHAMBERS

Thomas P. Chambers	
 	
Senior Vice President and Chief Financial Officer (Principal Financial Officer)	
 	
February 23, 2015	

/s/ PAUL M. NOBEL

Paul M. Nobel	
 	
Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	
 	
February 23, 2015	

/s/ SIR RICHARD B. DEARLOVE

Sir Richard B. Dearlove	
 	
Director	
 	
February 23, 2015	

/s/ DAVID I. FOLEY

David I. Foley	
 	
Director	
 	
February 23, 2015	

/s/ DAVID B. KRIEGER

David B. Krieger	
 	
Director	
 	
February 23, 2015	
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Signature	 	Title	 	Date	

 	

 	
/s/ JOSEPH P. LANDY

Joseph P. Landy	 	Director	 	February 23, 2015	

/s/ PRAKASH A. MELWANI

Prakash A. Melwani	
 	
Director	
 	
February 23, 2015	

/s/ ADEBAYO O. OGUNLESI

Adebayo O. Ogunlesi	
 	
Director	
 	
February 23, 2015	

/s/ LARS H. THUNELL

Lars H. Thunell	
 	
Director	
 	
February 23, 2015	

/s/ CHRIS TONG

Chris Tong	
 	
Director	
 	
February 23, 2015	

/s/ CHRISTOPHER A. WRIGHT

Christopher A. Wright	
 	
Director	
 	
February 23, 2015	
154

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INDEX OF EXHIBITS

Exhibit
Number	 	Description of Document	
 	 	 	Governing Documents	

3.1	
 	
Certificate of Incorporation of the Company (filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1/A filed March 23, 2011 (File No. 333-171700), and incorporated herein by reference).	

3.2	
 	
Memorandum of Association of the Company (filed as Exhibit 3.2 to the Company's Registration Statement on Form S-1/A filed March 23, 2011 (File No. 333-171700), and incorporated herein by reference).	

3.3	
 	
Bye-laws of the Company (filed as Exhibit 4 to the Company's Registration Statement on Form 8-A filed May 6, 2011 (File No. 001-35167), and incorporated herein by reference).	

4.1	
 	
Specimen share certificate (filed as Exhibit 4.1 to the Company's Registration Statement on Form S-1/A filed April 25, 2011 (File No. 333-171700), and incorporated herein by reference).	

 	
 	
Operating Agreements	

 	
 	
Ghana	

10.1	
 	
Petroleum Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 22, 2004 among the GNPC, Kosmos Ghana and the E.O. Group (filed as Exhibit 10.1 to the Company's Registration Statement on Form S-1/A filed March 3, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.2	
 	
Operating Agreement in respect of West Cape Three Points Block Offshore Ghana dated July 27, 2004 between Kosmos Ghana and E.O. Group (filed as Exhibit 10.2 to the Company's Registration Statement on Form S-1/A filed March 3, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.3	
 	
Petroleum Agreement in respect of the Deepwater Tano Contract Area dated March 10, 2006 among GNPC, Tullow Ghana, Sabre and Kosmos Ghana (filed as Exhibit 10.3 to the Company's Registration Statement on Form S-1/A filed March 3, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.4	
 	
Joint Operating Agreement in respect of the Deepwater Tano Contract Area, Offshore Ghana dated August 14, 2006, among Tullow Ghana, Sabre Oil and Gas Limited, and Kosmos Ghana (filed as Exhibit 10.4 to the Company's Registration Statement on Form S-1/A filed March 3, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.5	
 	
Assignment Agreement in respect of the Deepwater Tano Block dated September 1, 2006, among Anadarko WCTP and Kosmos Ghana (filed as Exhibit 10.5 to the Company's Registration Statement on Form S-1/A filed March 3, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.6	
 	
Unitization and Unit Operating Agreement covering the Jubilee Field Unit located offshore the Republic of Ghana dated July 13, 2009, among GNPC, Tullow, Kosmos Ghana, Anadarko WCTP, Sabre and E.O. Group (filed as Exhibit 10.6 to the Company's Registration Statement on Form S-1/A filed March 3, 2011 (File No. 333-171700), and incorporated herein by reference).	
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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 Company's Registration Statement on Form S-1/A filed April 14, 2011 (File No. 333-171700), and incorporated herein by reference).	

 	
 	
Morocco	

10.8	
 	
Petroleum Agreement regarding the exploration for 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 Company's Registration Statement on Form S-1/A 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 Company's Registration Statement on Form S-1/A 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 Company's Registration Statement on Form S-1/A 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 Company's 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 Company's 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 Company's 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 Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
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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 Company's 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 Company's 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 Company's 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 Company's 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 Company's 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 Company's 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 Company's 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 Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	
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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 Company's 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 Company's 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 Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	

 	
 	
Ireland	

10.26	
 	
Irish Continental Shelf—Petroleum Exploration License No. 1/13 (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 Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	

10.27	
 	
Irish Continental Shelf—Petroleum Exploration License No. 2/13 (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 Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	

10.28	
 	
Irish Continental Shelf—Petroleum Exploration License No. 3/13 (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 Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	

10.29	
 	
Licensing Terms for Offshore Oil and Gas Exploration, Development and Production 2007, relating to the Petroleum Exploration Licenses No. 1/13, No. 2/13 and No. 3/13 offshore Ireland (filed as Exhibit 10.26 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	

 	
 	
Drilling Rigs	

10.30	
 	
Deepwater Drilling Unit Contract Agreement, dated as of June 9, 2013, between Kosmos Energy Ventures and Alpha Offshore Drilling Services Company (filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference).	
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Exhibit
Number	 	Description of Document	
 	 	 	Financing Agreements	

10.31	
 	
Intercreditor Agreement, dated March 28, 2011 among BNP Paribas, Kosmos Finance International, Kosmos Operating, Kosmos International, Kosmos Development, Kosmos Ghana and the various financial institutions and others party thereto (filed as Exhibit 10.20 to the Company's Registration Statement on Form S-1/A filed April 25, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.32	
 	
Facility Agreement, dated February 17, 2012, among Kosmos Energy Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and International Finance Corporation (filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, and incorporated herein by reference).	

10.33	
 	
Deed of Transfer and Amendment, dated February 17, 2012, among Kosmos Energy Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC, BNP Paribas, Citibank N.A., Credit Suisse International, Société Générale London Branch and International Finance Corporation (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, and incorporated herein by reference).	

10.34	
 	
Deed of Guarantee and Indemnity, dated as of November 23, 2012, among Kosmos Energy Ltd., and Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and Kosmos Energy Finance International, as Original Guarantors, and BNP Paribas, as Security and Intercreditor Agent (filed as Exhibit 10.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, and incorporated herein by reference).	

10.35	
 	
Intercreditor Agreement, dated as of November 23, 2012, among Kosmos Energy Ltd., as HY Note Issuer and RCF Borrower, Kosmos Energy Finance International, as Original Senior Borrower, BNP Paribas, as Security Agent, Security and Intercreditor Agent and Proceeds Agent, and Standard Chartered Bank, as RCF Agent (filed as Exhibit 10.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, and incorporated herein by reference).	

10.36	
 	
Multi-Currency Revolving Letter of Credit Facility Agreement , dated as of July 3, 2013 and amended and restated on July 29, 2013, among Kosmos Energy Credit International, as the Original Borrower, Kosmos Energy Ltd., as the Original Guarantor, and Societe Generale, London Branch, as the Original Lender, Facility Agent, Security Agent and Account Bank (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference).	

10.37	
 	
Charge on Cash Deposits and Account Bank Agreement, dated as of July 3, 2013, among Kosmos Energy Credit International and Societe Generale, London Branch, as Security Agent and Account Bank (filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and incorporated herein by reference).	
159

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Exhibit
Number	 	Description of Document	
 	10.38	 	Deed of Amendment and Restatement relating to the Revolving Credit Facility Agreement, dated March 14, 2014, among Kosmos Energy Ltd., as Original Borrower, certain of its subsidiaries listed therein, as Original Guarantors, Standard Chartered Bank, as Facility Agent, BNP Paribas, as Security and Intercreditor Agent, and the financial institutions listed therein, as Original Lenders (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, and incorporated herein by reference).	

10.39	
 	
Deed of Amendment and Restatement relating to the Facility Agreement and a Charge over Shares in Kosmos Energy Operating, dated March 14, 2014, among Kosmos Energy Finance International, as Original Borrower, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development and Kosmos Energy Ghana HC, as Original Guarantors, Kosmos Energy Holdings, as Chargor, and BNP Paribas, as Facility Agent and Security Agent (filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, and incorporated herein by reference).	

10.40	
 	
Indenture, dated as of August 1, 2014, among the Company, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC and Kosmos Energy Finance International, Wilmington Trust, National Association, as trustee, transfer agent, registrar and paying agent and Banque Internationale à Luxembourg S.A., as Luxembourg listing agent, transfer agent and paying agent (including the Form of Notes) (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K filed August 4, 2014 (File No. 001-35167), and incorporated herein by reference).	

10.41	
 	
KEL Intercreditor and Security Sharing Agreement, dated as of August 1, 2014, among the Company, BNP Paribas, as security and intercreditor agent, Standard Chartered Bank, as RCF Agent and Wilmington Trust, National Association, as trustee, transfer agent, registrar and paying agent (filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed August 4, 2014 (File No. 001-35167), and incorporated herein by reference).	

 	
 	
Agreements with Shareholders and Directors	

10.42	
 	
Form of Director Indemnification Agreement (filed as Exhibit 10.27 to the Company's Registration Statement on Form S-1/A filed April 14, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.43	
 	
Shareholders Agreement, dated as of May 10, 2011, among Kosmos Energy Ltd. and the other parties signatory thereto (filed as Exhibit 9.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, and incorporated herein by reference).	

10.44	
 	
Registration Rights Agreement, dated as of October 7, 2009, among Kosmos Energy Holdings and the other parties signatory thereto (filed as Exhibit 10.32 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, and incorporated herein by reference).	

10.45	
 	
Joinder Agreement to the Registration Rights Agreement, dated as of May 10, 2011, among Kosmos Energy Ltd. and the other parties signatory thereto (filed as Exhibit 10.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, and incorporated herein by reference).	

10.46	
 	
Amendment No. 1 to the Registration Rights Agreement, dated as of February 8, 2013, among Kosmos Energy Ltd. and the other parties signatory thereto (filed as Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, and incorporated herein by reference).	
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Exhibit
Number	 	Description of Document	
 	 	 	Management Contracts/Compensatory Plans or Arrangements	

10.47	
†	
Long Term Incentive Plan (filed as Exhibit 99.1 to the Company's Registration Statement on Form S-8 filed May 16, 2011 (File No. 333-174234), and incorporated herein by reference).	

10.48	
†	
Annual Incentive Plan (filed as Exhibit 10.22 to the Company's Registration Statement on Form S-1/A filed March 30, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.49	
†	
Form of Restricted Stock Award Agreement (Exchange) (filed as Exhibit 10.24 to the Company's Registration Statement on Form S-1/A filed March 30, 2011 (File No. 333-171700), and incorporated herein by reference).	

10.50	
†*	
Form of Restricted Stock Award Agreement (Service Vesting).	

10.51	
†*	
Form of Restricted Stock Award Agreement (Performance Vesting).	

10.52	
†*	
Form of RSU Award Agreement (Service Vesting).	

10.53	
†*	
Form of RSU Award Agreement (Performance Vesting).	

10.54	
†*	
Form of Directors RSU Award Agreement (Service Vesting).	

10.55	
†	
Separation and Release Agreement, dated May 12, 2014 between Kosmos Energy, LLC and Darrell McKenna (filed as Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, and incorporated herein by reference).	

10.56	
†	
Offer Letter, dated September 1, 2011, between Kosmos Energy, LLC and Jason Doughty (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, and incorporated herein by reference).	

10.57	
†	
Offer Letter, dated May 22, 2013, between Kosmos Energy, LLC and Christopher Ball (filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, and incorporated herein by reference).	

10.58	
†	
Offer Letter, dated January 10, 2014, between Kosmos Energy, LLC and Andrew Inglis (filed as Exhibit 10.58 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, and incorporated herein by reference).	

10.59	
†	
Assignment Agreement, dated April 16, 2014, between Kosmos Energy, LLC and Brian F. Maxted (filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, and incorporated herein by reference).	

10.60	
†*	
Offer Letter, dated October 16, 2014, between Kosmos Energy, LLC and Thomas P. Chambers.	

10.61	
†	
Consulting Agreement dated October 31, 2011 between Kosmos Energy Ltd. and John R. Kemp III (filed as Exhibit 10.33 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference).	

10.62	
†	
Amendment No. 1 to Consulting Agreement dated February 23, 2012 between Kosmos Energy Ltd. and John R. Kemp III (filed as Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, and incorporated herein by reference).	
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Exhibit
Number	 	Description of Document	
 	10.63	†	Amendment No. 2, effective as of January 1, 2013, to Consulting Agreement between Kosmos Energy Ltd. and John R. Kemp III (filed as Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference)	

10.64	
†	
Amendment No. 3, effective as of October 1, 2013, to Consulting Agreement between Kosmos Energy Ltd. and John R. Kemp III (filed as Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, and incorporated herein by reference).	

10.65	
†	
Kosmos Energy Ltd. Change in Control Severance Policy for U.S. Employees, dated December 19, 2013 (filed as Exhibit 10.66 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, and incorporated herein by reference).	

 	
 	
Other Exhibits	

14.1	
 	
Code of Business Conduct and Ethics (filed as Exhibit 14.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011, and incorporated herein by reference).	

21.1	
*	
List of Subsidiaries.	

23.1	
*	
Consent of Ernst & Young LLP.	

23.2	
*	
Consent of Ryder Scott Company, L.P.	

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.	

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.—Jubilee Field	

99.2	
*	
Report of Ryder Scott Company, L.P.—TEN Project Area	

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.

162

EXHIBIT 10.50
 
KOSMOS ENERGY LTD.
[AMENDED AND RESTATED] LONG TERM INCENTIVE PLAN
 
Restricted Stock Award Agreement
[Service Vesting]
 
You have been granted Restricted Stock (this “Award”) on the following terms and subject to the provisions of Attachment A and the Kosmos Energy Ltd. [Amended and Restated] Long Term Incentive Plan (the “ Plan ”).  Unless defined in this Award agreement (including Attachment A, this “ Agreement ”), capitalized terms will have the meanings assigned to them in the Plan.  In the event of a conflict among the provisions of the Plan, this Agreement and any descriptive materials provided to you, the provisions of the Plan will prevail.
 
Participant	 	[Full name] (the “Participant”)	
 	 	 	
Number of Shares Underlying Award	 	[·] Shares (to the extent not vested as of any applicable date, the “Restricted Shares ”)	
 	 	 	
Grant Date	 	[·] (the “Grant Date”)	
 	 	 	
Vesting	 	Subject to Section 3 of Attachment A, the Restricted shares shall vest [insert applicable vesting date(s)] if the Participant does not experience a Termination of Service at any time prior to [such] [the applicable] vesting date. [Further, subject to Section 3 of Attachment A, if a Change in Control occurs, then the Restricted Shares that have not vested pursuant to the preceding sentence shall vest [insert applicable vesting date(s)] if the Participant does not experience a Termination of Service at any time prior to [such] [the applicable] vesting date.]	

 
Attachment A
 
Restricted Stock Award Agreement
Terms and Conditions
 
Grant to: [Full name]
 
Section 1.  Grant of Restricted Stock Award.  Subject to the terms and conditions of the Plan and this Agreement, the Company hereby grants this Award to the Participant on the Grant Date on the terms set forth on the cover page of this Agreement, as more fully described in this Attachment A.  This Award is granted under the Plan, which is incorporated herein by this reference and made a part of this Agreement.
 
Section 2.  Issuance of Shares.
 
(a)                                The Restricted Shares shall be evidenced by entry into the register of members of the Company; provided, however , that the Committee may determine that the Restricted Shares shall be evidenced in such other manner as it deems appropriate, including the issuance of a share certificate or certificates.  In the event that any share certificate is issued in respect of the Restricted Shares, such certificate shall (i) be registered in the name of the Participant, (ii) bear an appropriate legend referring to the terms, conditions and restrictions applicable to the Restricted Shares and (iii) be held in custody by the Company.
 
(b)                                Voting Rights.  The Participant shall have voting rights with respect to the Restricted Shares.
 
(c)                                 Dividends.  All cash and other dividends and distributions, if any, that are paid with respect to the Restricted Shares shall be paid currently to the Participant.
 
(d)                                Transferability.  Unless and until the Restricted Shares become vested in accordance with this Agreement, the Restricted Shares shall not be assigned, sold, transferred or otherwise be subject to alienation by the Participant.
 
[(e)                             Section 83(b) Election.  If the Participant chooses, the Participant may make an election under Section 83(b) of the Code with respect to the Restricted Shares, which would cause the Participant currently to recognize income for U.S. federal income tax purposes in an amount equal to the excess (if any) of the Fair Market Value of the Restricted Shares (determined as of the Grant Date) over the amount, if any, that the Participant paid for the Restricted Shares, which excess will be subject to U.S. federal income tax.  The form for making a Section 83(b) election is available from the Company at the address indicated in Section 4(a).   The Participant acknowledges that (i) the Participant is solely
 
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responsible for the decision whether or not to make a Section 83(b) election, and the Company is not making any recommendation with respect thereto, (ii) it is the Participant’s sole responsibility to timely file the Section 83(b) election within 30 days after the Grant Date, if the Participant decides to make such election, and (iii) if the Participant does not make a valid and timely Section 83(b) election, the Participant will be required to recognize ordinary income at the time of vesting on any future appreciation on the Restricted Shares. ]
 
[(e)                             No Section 83(b) Election.  The Participant agrees that he shall not make an election under Section 83(b) of the Code with respect to the Restricted Shares.]
 
(f)                                  Withholding Requirements.  The Company may withhold any tax (or other governmental obligation) that becomes due with respect to the Restricted Shares (or any dividend or distribution thereon[, or on any cash payment made pursuant to the right described in Section 3(e)(ii)] (1) ), and the Participant shall make arrangements satisfactory to the Company to enable the Company to satisfy all such withholding requirements.  Notwithstanding the foregoing, the Committee, in its sole discretion, may permit the Participant to satisfy any such withholding requirement by transferring to the Company pursuant to such procedures as the Committee may require, effective as of the date on which such requirement arises, a number of vested Shares owned and designated by the Participant having an aggregate Fair Market Value as of such date that is equal to the minimum amount required to be withheld.  If the Committee permits the Participant to satisfy any such withholding requirement pursuant to the preceding sentence, the Company shall remit to the Internal Revenue Service and appropriate state and local revenue agencies, for the credit of the Participant, an amount of cash withholding equal to the Fair Market Value of the Shares transferred to the Company as provided above.
 
Section 3.  Accelerated Vesting and Forfeiture upon Termination of Service.
 
(a)                                Death or Disability. In the event of the Participant’s Termination of Service at any time due to the Participant’s death or Disability, the Restricted Shares shall fully vest.
 
[(b)                            Without Cause or for Good Reason [within [insert applicable period] After a Change in Control]. In the event of the Participant’s Termination of Service [on the date upon which a Change in Control occurs or within [insert applicable period]] (2)  by the Company or any Affiliate without Cause or by the

(1)  Include if applicable.
 
(2)  Include if applicable.
 
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Participant for Good Reason, then, in any such case, the Restricted Shares shall fully vest.]
 
[(b)                            Replacement of Award on Change in Control. In the event of a Change in Control, the Restricted Shares shall be converted into restricted Pubco Shares (as defined below) or shall be forfeited and replaced with the right to receive cash, as follows:
 
(i)                                    If, as of immediately following such Change in Control, the shares of the surviving or resulting entity (or the direct or indirect parent of such entity) in such Change in Control are quoted or traded on a stock market or exchange (“ Pubco Shares ”), the Restricted Shares shall be converted into a number of restricted Pubco Shares having an aggregate Fair Market Value as of immediately following such Change in Control that is equal to the aggregate Fair Market Value of the Restricted Shares as of immediately prior to such Change in Control.
 
(ii)                                 If, as of immediately following such Change in Control, the shares of the surviving or resulting entity (or the direct or indirect parent of such entity) in such Change in Control are not quoted or traded on a stock market or exchange, the Restricted Shares shall be forfeited in their entirety without any payment to the Participant (or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the Restricted Shares at their par value) and replaced with the right to receive, upon the vesting thereof, an amount in cash equal to the aggregate Fair Market Value of the Restricted Shares as of immediately prior to such Change in Control.
 
[(iii)                          In the event of the Participant’s Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason, in either case at any time during the period beginning three months before and ending one year after the date on which a Change in Control occurs, the Restricted Shares that have not vested as of the date of such Termination of Service shall fully vest on the later of (i) the date of such Termination of Service or (ii) the date on which such Change in Control occurs;  provided ,  however , that in the case of any such Termination of Service that occurs during the three-month period prior to the date on which such Change in Control occurs, such vesting of the Restricted Shares shall only apply if such Termination of Service was at the request of a third party that has taken steps reasonably calculated to effectuate such Change in Control or that otherwise arose in connection with or anticipation of such Change in Control.] (3)

(3)  For Andrew G. Inglis, the Chief Executive Officer of the Company.
 
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[(iii)                          In the event that, upon such Change in Control or within one year thereafter, the Participant experiences a Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason, this Award shall fully vest.] (4)
 
(iv)                             Following such Change in Control, this Award shall remain subject to the terms set forth in this Agreement (including the vesting, forfeiture and distribution provisions herein), as modified by this Section 3(b).]
 
(c)                                 For Any Other Reason.  In the event of the Participant’s Termination of Service at any time under circumstances not described in Section 3(a) or 3(b)[(iii)], the Restricted Shares shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the Restricted Shares at their par value.
 
(d)                                Effect of Vesting.  Subject to the provisions of this Agreement, upon the vesting of any of the Restricted Shares, the restrictions under this Award with respect to such Shares shall lapse.  Subject to any applicable Lock Up Agreement, such Shares shall be fully assignable, saleable and transferable by the Participant, and the Company shall deliver such Shares to the Participant by transfer to the Depository Trust Company for the benefit of the Participant or by delivery of a share certificate registered in the Participant’s name and such transfer shall be evidenced in the register of members of the Company.
 
[(e)                             Effect of Failure to Obtain Shareholder Approval of the Plan.Notwithstanding anything in this Agreement to the contrary, if the Company’s shareholders do not approve the Plan, as amended by the Board on January 23, 2015, at the 2015 annual general meeting of the Company’s shareholders, (i) the Restricted Shares shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the Restricted Shares at their par value, and (ii) the Participant thereafter shall have the right to receive cash payments on (or within 30 days after) the vesting dates set forth in this Agreement, with the amount of each such payment equal to the Fair Market Value of the Shares (and any dividends or distributions thereon), as of such vesting date, that otherwise would have vested on such date.] (5)

(4)  For executive officers other than Andrew G. Inglis.
 
(5)  Include if applicable.
 
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Section 4.  Miscellaneous Provisions.
 
(a)                                Notices.  All notices, requests and other communications under this Agreement shall be in writing and shall be delivered in person (by courier or otherwise), mailed by certified or registered mail, return receipt requested, or sent by facsimile transmission, as follows:
 
if to the Company, to:
 
Kosmos Energy Ltd.
c/o Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231
Attention:  [·]
 
if to the Participant, to the address that the Participant most recently provided to the Company,
 
or to such other address or facsimile number as such party may hereafter specify for the purpose by notice to the other parties hereto.  All such notices, requests and other communications shall be deemed received on the date of receipt by the recipient thereof if received prior to 5:00 p.m. on a business day in the place of receipt.  Otherwise, any such notice, request or communication shall be deemed received on the next succeeding business day in the place of receipt.
 
(b)                                Entire Agreement.  This Agreement, the Plan and any other agreements, schedules, exhibits and other documents referred to herein or therein constitute the entire agreement and understanding between the parties in respect of the subject matter hereof and supersede all prior and contemporaneous arrangements, agreements and understandings, both oral and written, whether in term sheets, presentations or otherwise, between the parties with respect to the subject matter hereof.
 
(c)                                 Amendment; Waiver.  No amendment or modification of any provision of this Agreement shall be effective unless signed in writing by or on behalf of the Company and the Participant, except that the Company may amend or modify this Agreement without the Participant’s consent in accordance with the provisions of the Plan or as otherwise set forth in this Agreement.  No waiver of any breach or condition of this Agreement shall be deemed to be a waiver of any other or subsequent breach or condition whether of like or different nature.  Any amendment or modification of or to any provision of this Agreement, or any waiver of any provision of this Agreement, shall be effective only in the specific instance and for the specific purpose for which made or given.
 
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(d)                                Assignment.  Neither this Agreement nor any right, remedy, obligation or liability arising hereunder or by reason hereof shall be assignable by the Participant.
 
(e)                                 Successors and Assigns; No Third Party Beneficiaries.  This Agreement shall inure to the benefit of and be binding upon the Company and the Participant and their respective heirs, successors, legal representatives and permitted assigns.  Nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Company and the Participant, and their respective heirs, successors, legal representatives and permitted assigns, any rights, remedies, obligations or liabilities under or by reason of this Agreement.
 
(f)                                  Counterparts.  This Agreement may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
 
(g)                                 Participant Undertaking.  The Participant agrees to take whatever additional action and execute whatever additional documents the Company may deem necessary or advisable to carry out or give effect to any of the obligations or restrictions imposed on either the Participant or the Restricted Shares pursuant to the provisions of this Agreement.
 
(h)                                Plan.  The Participant acknowledges and understands that material definitions and provisions concerning the Restricted Shares and the Participant’s rights and obligations with respect thereto are set forth in the Plan.  The Participant has read carefully, and understands, the provisions of the Plan.
 
(i)                                    Dispute Resolution.  If any dispute arising out of or relating to this Agreement or the Plan, or the breach thereof, cannot be settled through negotiation, the parties agree first to try in good faith to settle such dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules.  If the parties fail to settle such dispute within 30 days after the commencement of such mediation, such dispute shall be settled by arbitration administered by the American Arbitration Association under its Commercial Arbitration Rules, and judgment on the arbitral award rendered may be entered in any court having jurisdiction thereof.
 
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IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first written above.

 	KOSMOS ENERGY LTD.	

 	By:	 	
 	 	Name:	
 	 	Title:	

 	 	[Name of Participant]	
 
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EXHIBIT 10.51
 
KOSMOS ENERGY LTD.
[AMENDED AND RESTATED] LONG TERM INCENTIVE PLAN
 
Restricted Stock Award Agreement
[Performance Vesting]
 
You have been granted Restricted Stock (this “Award”) on the following terms and subject to the provisions of Attachments A and B and the Kosmos Energy Ltd. [Amended and Restated] Long Term Incentive Plan (the “ Plan ”).  Unless defined in this Award agreement (including Attachments A and B, this “ Agreement ”), capitalized terms will have the meanings assigned to them in the Plan.  In the event of a conflict among the provisions of the Plan, this Agreement and any descriptive materials provided to you, the provisions of the Plan will prevail.
 
Participant	 	[·] (the “Participant”)	
 	 	 	
Number of Shares Underlying Award	 	[·] Shares (to the extent not vested as of any applicable date, the “Restricted Shares ”)	
 	 	 	
Grant Date	 	[·] (the “Grant Date”)	
 	 	 	
Vesting	 	Subject to Section 3 of Attachment A, the Restricted Shares shall vest and become non-forfeitable to the extent that both the applicable “Service Condition” and the applicable “Performance Condition” (as such terms are defined below) with respect to such Shares are satisfied.	
 	 	 	
Service Condition	 	Subject to Section 3 of Attachment A, the “Service Condition” shall be satisfied [insert applicable date(s)], in each case if the Participant does not experience a Termination of Service at any time prior to [such] [the applicable] date.	
 	 	 	
Performance Condition	 	Subject to Section 3 of Attachment A, the “Performance Condition” shall be deemed satisfied with respect to between 0% and 100% of the Restricted Shares based on attainment of Relative TSR as of the End Date, as detailed in Attachment B.	

 
Attachment A
 
Restricted Stock Award Agreement
Terms and Conditions
 
Grant to:[Full Name]
 
Section 1.  Grant of Restricted Stock Award.  Subject to the terms and conditions of the Plan and this Agreement, the Company hereby grants this Award to the Participant on the Grant Date on the terms set forth on the cover page of this Agreement, as more fully described in this Attachment A and in Attachment B.  This Award is granted under the Plan, which is incorporated herein by this reference and made a part of this Agreement.
 
Section 2.  Issuance of Shares.
 
(a)                                The Restricted Shares shall be evidenced by entry into the register of members of the Company; provided, however , that the Committee may determine that the Restricted Shares shall be evidenced in such other manner as it deems appropriate, including the issuance of a share certificate or certificates.  In the event that any share certificate is issued in respect of the Restricted Shares, such certificate shall (i) be registered in the name of the Participant, (ii) bear an appropriate legend referring to the terms, conditions and restrictions applicable to the Restricted Shares and (iii) be held in custody by the Company.
 
(b)                                Voting Rights.  The Participant shall have voting rights with respect to the Restricted Shares.
 
(c)                                 Dividends.  Until the Service Condition and the Performance Condition (collectively, the “ Conditions ”) are satisfied with respect to a Restricted Share, the dividends and other distributions that are paid or distributed with respect to such Restricted Share (whether in the form of Shares or other property (including cash)) (referred to herein as “ Distributions ”) shall be subject to the risk of forfeiture applicable to such Restricted Share and shall be held by the Company or other depository as may be designated by the Committee as a depository for safekeeping.  If the Restricted Share to which such Distributions relate is forfeited (including by way of repurchase by the Company at its par value) prior to the satisfaction of the Conditions applicable to such Restricted Share, then such Distributions shall be forfeited to the Company at the same time as such Restricted Share is so forfeited.  If the Conditions applicable to the Restricted Share to which such Distributions relate are satisfied in accordance with this Agreement, then such Distributions shall be paid and distributed to the Participant as soon as administratively feasible after such Conditions are satisfied (but in no event later than March 15 of the calendar year following the calendar year in which such Conditions are satisfied), and Distributions with respect to such Restricted Share that occur after satisfaction of the Conditions and prior to the forfeiture, if any, of such Restricted Share (including by way of repurchase by the
 
A-1

 
Company at its par value) shall be paid currently to the Participant.  Distributions paid or distributed with respect to Restricted Shares shall bear such legends, if any, as may be determined by the Committee to reflect the terms and conditions of this Agreement and to comply with applicable securities laws.
 
(d)                                Transferability.  Unless and until the Restricted Shares become vested in accordance with this Agreement, the Restricted Shares shall not be assigned, sold, transferred or otherwise be subject to alienation by the Participant.
 
(e)                                 Section 83(b) Election.  If the Participant chooses, the Participant may make an election under Section 83(b) of the Code with respect to the Restricted Shares, which would cause the Participant currently to recognize income for U.S. federal income tax purposes in an amount equal to the excess (if any) of the Fair Market Value of the Restricted Shares (determined as of the Grant Date) over the amount, if any, that the Participant paid for the Restricted Shares, which excess will be subject to U.S. federal income tax.  The form for making a Section 83(b) election is available from the Company at the address indicated in Section 4(a).   The Participant acknowledges that (i) the Participant is solely responsible for the decision whether or not to make a Section 83(b) election, and the Company is not making any recommendation with respect thereto, (ii) it is the Participant’s sole responsibility to timely file the Section 83(b) election within 30 days after the Grant Date, if the Participant decides to make such election, and (iii) if the Participant does not make a valid and timely Section 83(b) election, the Participant will be required to recognize ordinary income at the time of vesting on any future appreciation on the Restricted Shares.
 
(f)                                  Withholding Requirements.  Except with respect to any withholding requirement resulting from the Participant’s election under Section 83(b) of the Code, the Company may withhold any tax (or other governmental obligation) that becomes due with respect to the Restricted Shares (or any dividend or distribution thereon), and the Participant shall make arrangements satisfactory to the Company to enable the Company to satisfy all such withholding requirements.  Notwithstanding the foregoing, the Committee, in its sole discretion, may permit the Participant to satisfy any such withholding requirement by transferring to the Company pursuant to such procedures as the Committee may require, effective as of the date on which such requirement arises, a number of vested Shares owned and designated by the Participant having an aggregate Fair Market Value as of such date that is equal to the minimum amount required to be withheld.  If the Committee permits the Participant to satisfy any such withholding requirement pursuant to the preceding sentence, the Company shall remit to the Internal Revenue Service and appropriate state and local revenue agencies, for the credit of the Participant, an amount of cash withholding equal to the Fair Market Value of the Shares transferred to the Company as provided above.
 
A-2

 
Section 3.  Accelerated Vesting and Forfeiture.
 
(a)                                Termination of Service.
 
(i)                                    Death or Disability.  In the event of the Participant’s Termination of Service at any time due to the Participant’s death or Disability, the Service Condition shall be deemed fully satisfied as of such termination; provided  that, if such termination occurs prior to the End Date, then, subject to Section 3(b), the Restricted Shares shall remain subject to the Performance Condition.
 
(ii)                                 Without Cause or for Good Reason.  In the event of the Participant’s Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason [[Option 1: the Service Condition shall be deemed fully satisfied as of such termination;  provided  that, if such termination occurs prior to the End Date, then, subject to Section 3(b), the Restricted Shares shall remain subject to the Performance Condition] [Option 2: and other than as described in Section 3(b) below, (x) the Restricted Shares, if any, for which the applicable Service Condition is satisfied as of such termination shall remain subject to the Performance Condition (if such termination occurs at any time prior to the End Date)  and (y) the Restricted Shares, if any, for which the applicable Service Condition is not satisfied as of such termination shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the Restricted Shares at their par value]] (1) .
 
(iii)                              Without Good Reason.  In the event of the Participant’s Termination of Service by the Participant without Good Reason at any time prior to the End Date, (x) the Restricted Shares, if any, for which the applicable Service Condition is satisfied as of such termination shall remain subject to the Performance Condition and (y) the Restricted Shares, if any, for which the applicable Service Condition is not satisfied as of such termination shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the Restricted Shares at their par value.
 
(iv)                             For Cause.  In the event of the Participant’s Termination of Service at any time by the Company or any Affiliate for Cause, the Restricted Shares shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required

(1)  Include Option 1 or Option 2, as applicable.
 
A-3

 
pursuant to applicable law to effect such forfeiture, the Company may repurchase the Restricted Shares at their par value.
 
(b)                                Change in Control.  If a Change in Control occurs and the Participant does not experience a Termination of Service at any time prior to such Change in Control, the Performance Condition shall be deemed fully satisfied as of the date of such Change in Control and, following such Change in Control, (x) [insert applicable fraction] of the Restricted Shares will vest in the event that any anniversary of [the Grant Date] [insert applicable vesting commencement date] occurs during the first year after such Change in Control, and (y) all of the remaining Restricted Shares will fully vest on the earlier of (A) the first anniversary of such Change in Control, if the Participant does not experience a Termination of Service at any time prior to such anniversary, and (B) the Participant’s Termination of Service due to the Participant’s death or Disability, by the Company or any Affiliate without Cause or by the Participant for Good Reason.
 
(c)                                 Effect of Vesting.  Subject to the provisions of this Agreement, upon the vesting of any of the Restricted Shares, the restrictions under this Award with respect to such Shares shall lapse.  Subject to any applicable Lock Up Agreement, such Shares shall be fully assignable, saleable and transferable by the Participant, and the Company shall deliver such Shares to the Participant by transfer to the Depository Trust Company for the benefit of the Participant or by delivery of a share certificate registered in the Participant’s name and such transfer shall be evidenced in the register of members of the Company.
 
(d)                                Effect of Failure to Achieve Performance Condition.  On the End Date, any of the Restricted Shares for which the Performance Condition is not satisfied as of such date shall be forfeited without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the Restricted Shares at their par value.
 
Section 4.  Miscellaneous Provisions.
 
(a)                                Notices.  All notices, requests and other communications under this Agreement shall be in writing and shall be delivered in person (by courier or otherwise), mailed by certified or registered mail, return receipt requested, or sent by facsimile transmission, as follows:
 
if to the Company, to:
 
Kosmos Energy Ltd.
c/o Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231
Attention:  [·]
 
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if to the Participant, to the address that the Participant most recently provided to the Company,
 
or to such other address or facsimile number as such party may hereafter specify for the purpose by notice to the other parties hereto.  All such notices, requests and other communications shall be deemed received on the date of receipt by the recipient thereof if received prior to 5:00 p.m. on a business day in the place of receipt.  Otherwise, any such notice, request or communication shall be deemed received on the next succeeding business day in the place of receipt.
 
(b)                                Entire Agreement.  This Agreement, the Plan and any other agreements, schedules, exhibits and other documents referred to herein or therein constitute the entire agreement and understanding between the parties in respect of the subject matter hereof and supersede all prior and contemporaneous arrangements, agreements and understandings, both oral and written, whether in term sheets, presentations or otherwise, between the parties with respect to the subject matter hereof.
 
(c)                                 Amendment; Waiver.  No amendment or modification of any provision of this Agreement shall be effective unless signed in writing by or on behalf of the Company and the Participant, except that the Company may amend or modify this Agreement without the Participant’s consent in accordance with the provisions of the Plan or as otherwise set forth in this Agreement.  No waiver of any breach or condition of this Agreement shall be deemed to be a waiver of any other or subsequent breach or condition whether of like or different nature.  Any amendment or modification of or to any provision of this Agreement, or any waiver of any provision of this Agreement, shall be effective only in the specific instance and for the specific purpose for which made or given.
 
(d)                                Assignment.  Neither this Agreement nor any right, remedy, obligation or liability arising hereunder or by reason hereof shall be assignable by the Participant.
 
(e)                                 Successors and Assigns; No Third Party Beneficiaries.  This Agreement shall inure to the benefit of and be binding upon the Company and the Participant and their respective heirs, successors, legal representatives and permitted assigns.  Nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Company and the Participant, and their respective heirs, successors, legal representatives and permitted assigns, any rights, remedies, obligations or liabilities under or by reason of this Agreement.
 
(f)                                  Counterparts.  This Agreement may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
 
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(g)                                 Participant Undertaking.  The Participant agrees to take whatever additional action and execute whatever additional documents the Company may deem necessary or advisable to carry out or give effect to any of the obligations or restrictions imposed on either the Participant or the Restricted Shares pursuant to the provisions of this Agreement.
 
(h)                                Plan.  The Participant acknowledges and understands that material definitions and provisions concerning the Restricted Shares and the Participant’s rights and obligations with respect thereto are set forth in the Plan.  The Participant has read carefully, and understands, the provisions of the Plan.
 
(i)                                    Dispute Resolution.  If any dispute arising out of or relating to this Agreement or the Plan, or the breach thereof, cannot be settled through negotiation, the parties agree first to try in good faith to settle such dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules.  If the parties fail to settle such dispute within 30 days after the commencement of such mediation, such dispute shall be settled by arbitration administered by the American Arbitration Association under its Commercial Arbitration Rules, and judgment on the arbitral award rendered may be entered in any court having jurisdiction thereof.
 
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IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first written above.

 	KOSMOS ENERGY LTD.	

 	By:	 	
 	 	Name:	 	
 	 	Title:	 	

 	 	[Name of Participant]	
 
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Attachment B
 
Performance Condition
 
Section 1.  Definitions.  As used in this Attachment B, the following terms shall have the meanings set forth below:
 
(a)                                “End Date” means [·]
 
(b)                                “End Price” with respect to a Share or a Peer Share means the average of the closing price of such Share or Peer Share on each of the [ · ] trading days ending with the End Date on the applicable Principal Exchange; provided  that, if such Principal Exchange is a non-U.S. stock market or exchange, each such closing price shall be converted to U.S. dollars at the applicable spot exchange rate as of such trading day;  provided further  that the Committee shall adjust equitably the End Price with respect to such Share or Peer Share, as calculated in accordance with the preceding clause, to reflect any corporate transaction or event set forth in Section 5(c) of the Plan that affects such Share or Peer Share if such adjustment is appropriate to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under this Award.
 
(c)                                 “Grant Year” means the year in which the Grant Date occurs.
 
(d)                                “Peer” means any of the following companies whose shares are quoted or traded on the End Date on a Principal Exchange: [Africa Oil Corp.,] Anadarko Petroleum Corporation, [Apache Corporation,] BG Group plc, Cairn Energy plc, Cobalt International Energy, Inc., [Genel Energy plc,] [HRT Participacoes em Petroleo SA,] Lundin Petroleum AB, Noble Energy, Inc., [Ophir Energy plc,] Premier Oil plc [,][and] Tullow Oil plc [and] [insert additional peer companies, if applicable].
 
(e)                                 “Peer Share” means the share of a Peer that is quoted or traded on a national securities exchange.
 
(f)                                  “Principal Exchange” means the principal U.S. securities exchange or non-U.S. stock market or exchange on which a Share or Peer Share is quoted or traded as of an applicable date.  For the avoidance of doubt, a Share or Peer Share that is quoted or traded only over the counter shall not be deemed to be quoted or traded on a Principal Exchange.
 
(g)                                 “Relative TSR” means the percentile ranking of the TSR of a Share in relation to the TSR of each of the Peers’ Shares, as calculated by the Committee in good faith applying a reasonable statistical method.
 
(h)                                “Start Date” means [·].
 
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(i)                                    “Start Price” with respect to a Share or a Peer Share means the average of the closing price of such Share or Peer Share on each of the [ · ] trading days ending with the Start Date on the applicable Principal Exchange; provided  that, if such Principal Exchange is a non-U.S. stock market or exchange, such closing price shall be converted to U.S. dollars at the applicable spot exchange rate on such date;  provided further  that the Committee shall adjust equitably the Start Price with respect to such Share or Peer Share, as calculated in accordance with the preceding clause, to reflect any corporate transaction or event set forth in Section 5(c) of the Plan that affects such Share or Peer Share if such adjustment is appropriate to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under this Award.
 
(j)                                   “TSR” with respect to a Share or Peer Share means (i) the sum of (x) the End Price of such Share or Peer Share minus the Start Price of such Share or Peer Share and (y) the aggregate amount of the dividends, if any, paid on such Share or Peer Share for any dividend record dates that occur during the period beginning on the Start Date and ending on the End Date, divided by (ii) such Start Price.
 
Section 2.  Performance Condition Attainment.  [Insert table setting forth the percentage (between 0% and 100%) of the Restricted Shares for which the Performance Condition shall be deemed satisfied based on the percentile attainment of Relative TSR (between 0 and 100) indicated in the corresponding row of the table]
 
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EXHIBIT 10.52
 
KOSMOS ENERGY LTD.
[AMENDED AND RESTATED] LONG TERM INCENTIVE PLAN
 
RSU Award Agreement
[Service Vesting]
 
You have been granted a restricted share unit award (this “Award”) on the following terms and subject to the provisions of Attachment A and the Kosmos Energy Ltd. [Amended and Restated] Long Term Incentive Plan (the “ Plan ”).  Unless defined in this Award agreement (including Attachment A, this “ Agreement ”), capitalized terms will have the meanings assigned to them in the Plan.  In the event of a conflict among the provisions of the Plan, this Agreement and any descriptive materials provided to you, the provisions of the Plan will prevail.
 
Participant	 	[Full name] (the “Participant”)	
 	 	 	
Number of Restricted Share Units	 	[·] Restricted Share Units (the “RSUs” or “Restricted Share Units”)	
 	 	 	
Grant Date	 	[·] (the “Grant Date”)	
 	 	 	
Vesting	 	Subject to Section 3 of Attachment A, the RSUs shall vest [insert applicable vesting date(s)] if the Participant does not experience a Termination of Service at any time prior to [such] [the applicable] vesting date. [Further, subject to Section 3 of Attachment A, if a Change in Control occurs, then the RSUs that have not vested pursuant to the preceding sentence shall vest [insert applicable vesting date(s)] if the Participant does not experience a Termination of Service at any time prior to [such] [the applicable] vesting date.]	

 
Attachment A
 
RSU Award Agreement
Terms and Conditions
 
Grant to: [Full name]
 
Section 1.  Grant of RSU Award.  Subject to the terms and conditions of the Plan and this Agreement, the Company hereby grants this Award to the Participant on the Grant Date on the terms set forth on the cover page of this Agreement, as more fully described in this Attachment A.  This Award is granted under the Plan, which is incorporated herein by this reference and made a part of this Agreement.
 
Section 2.  Issuance of RSUs.
 
(a)                                Issuance. Each RSU shall represent the right to receive one Share upon the vesting of such RSU in accordance with this Agreement.
 
(b)                                Voting Rights.  The Participant shall have no voting rights with respect to the RSUs unless and until the Participant becomes the record owner of the Shares, including Dividend Shares (as defined below) to the extent applicable, underlying such RSUs.
 
(c)                                 Dividend Equivalents. If a dividend is paid on Shares during the period commencing on the Grant Date and ending on the date on which the Shares underlying RSUs are distributed to the Participant, the Participant shall be eligible to receive an amount equal to the amount of the dividend that the Participant would have received had the Shares underlying the RSUs been distributed to the Participant as of the time at which such dividend is paid;  it being understood  that no such amount shall be payable with respect to any RSUs that are forfeited.  Such amount shall be paid to the Participant on the date on which the Shares underlying the RSUs are distributed to the Participant in the same form (cash, Shares or other property) in which such dividend is paid to holders of Shares generally.  Any Shares that the Participant is eligible to receive pursuant to this Section 2 are referred to herein as “ Dividend Shares .”
 
(d)                                Transferability.  The RSUs shall not be assigned, sold, transferred or otherwise be subject to alienation by the Participant.  Any assignment, sale, transfer or other alienation with respect to the Shares issuable upon the vesting of the RSUs shall be in accordance with applicable securities laws.
 
(e)                                 Withholding Requirements.  The Company may withhold any tax (or other governmental obligation) that becomes due with respect to the RSUs (or any dividend or distribution thereon), and the Participant shall make arrangements satisfactory to the Company to enable the Company to satisfy all such
 
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withholding requirements. Notwithstanding the foregoing, the Committee, in its sole discretion, may permit the Participant to satisfy any such withholding requirement by transferring to the Company pursuant to such procedures as the Committee may require, effective as of the date on which such requirement arises, a number of vested Shares owned and designated by the Participant having an aggregate Fair Market Value as of such date that is equal to the minimum amount required to be withheld.  If the Committee permits the Participant to satisfy any such withholding requirement pursuant to the preceding sentence, the Company shall remit to the Internal Revenue Service and appropriate state and local revenue agencies, for the credit of the Participant, an amount of cash withholding equal to the Fair Market Value of the Shares transferred to the Company as provided above.
 
Section 3.  Accelerated Vesting, Forfeiture upon Termination of Service and Distribution.
 
(a)                                Death or Disability.  In the event of the Participant’s Termination of Service at any time due to the Participant’s death or Disability, the RSUs that have not vested as of the date of such Termination of Service shall fully vest.
 
[(b)                            Without Cause or for Good Reason in Connection with a Change in Control.  In the event of the Participant’s Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason, in either case at any time during the period beginning three months before and ending one year after the date on which a Change in Control occurs, the RSUs that have not vested as of the date of such Termination of Service shall fully vest on the later of (i) the date of such Termination of Service or (ii) the date on which such Change in Control occurs;  provided ,  however , that in the case of any such Termination of Service that occurs during the three-month period prior to the date on which such Change in Control occurs, such vesting of the RSUs shall only apply if such Termination of Service was at the request of a third party that has taken steps reasonably calculated to effectuate such Change in Control or that otherwise arose in connection with or anticipation of such Change in Control.] (1)
 
[(b)                            Without Cause or for Good Reason [within [insert applicable period] After a Change in Control].  In the event of the Participant’s Termination of Service [on the date upon which a Change in Control occurs or within [insert applicable period]] (2)  by the Company or any Affiliate without Cause or by the Participant for Good Reason, then, in any such case, the RSUs shall fully vest.]
 
[(b)                            Replacement of Award on Change in Control. In the event of a Change in Control, this Award shall cease to represent the right to receive Shares

(1)  For Andrew G. Inglis, the Chief Executive Officer of the Company.
 
(2)  Include if applicable.
 
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and shall instead represent the right to receive Pubco Shares (as defined below) or cash, as follows:
 
(i)            If, as of immediately following such Change in Control, the shares of the surviving or resulting entity (or the direct or indirect parent of such entity) in such Change in Control are quoted or traded on a stock market or exchange (“ Pubco Shares ”), this Award shall represent the right to receive, upon the vesting thereof, a number of Pubco Shares having an aggregate Fair Market Value as of immediately following such Change in Control that is equal to the aggregate Fair Market Value of the Shares underlying this Award as of immediately prior to such Change in Control.
 
(ii)         If, as of immediately following such Change in Control, the shares of the surviving or resulting entity (or the direct or indirect parent of such entity) in such Change in Control are not quoted or traded on a stock market or exchange, this Award shall represent the right to receive, upon the vesting thereof, an amount in cash equal to the aggregate Fair Market Value of the Shares underlying this Award as of immediately prior to such Change in Control.
 
(iii)      In the event that, upon such Change in Control or within one year thereafter, the Participant experiences a Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason, this Award shall fully vest.
 
(iv)     Following such Change in Control, this Award shall remain subject to the terms set forth in this Agreement (including the vesting, forfeiture and distribution provisions herein), as modified by this Section 3(b).]
 
(c)                             For Any Other Reason.  In the event of the Participant’s Termination of Service at any time under circumstances not described in Section 3(a) or 3(b)[(iii)], the RSUs shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the RSUs at their par value.
 
(d)                                Distribution on Vesting.  Subject to the provisions of this Agreement, upon the vesting of any of the RSUs, the Company shall distribute to the Participant, on or within 30 days after the date of such vesting, one Share for each such RSU and the number of Dividend Shares, if any, determined in accordance with Section 2(c) of this Attachment A.  Subject to any applicable Lock Up Agreement, on such distribution, such Shares (including Dividend Shares) shall be fully assignable, saleable and transferable by the Participant, and the Company shall deliver such Shares to the Participant by transfer or issuance to the Depository Trust Company for the benefit of the Participant or by delivery of
 
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a share certificate registered in the Participant’s name and such transfer or issuance shall be evidenced in the register of members of the Company.
 
[(e)          Effect of Failure to Obtain Shareholder Approval of the Plan. Notwithstanding anything in this Agreement to the contrary, if, as of the date on which any of the RSUs vest, the Company’s shareholders have not approved the Plan, as amended by the Board on January 23, 2015, the Company shall pay to the Participant, in lieu of the Shares (including any Dividend Shares) that otherwise would have been distributed to the Participant pursuant to Section 3(d), on or within 30 days after such vesting date, an amount in cash equal to the aggregate Fair Market Value, as of such vesting date, of such Shares.] (3)
 
Section 4.  Miscellaneous Provisions.
 
(a)                                Notices.  All notices, requests and other communications under this Agreement shall be in writing and shall be delivered in person (by courier or otherwise), mailed by certified or registered mail, return receipt requested, or sent by facsimile transmission, as follows:
 
if to the Company, to:
 
Kosmos Energy Ltd.
c/o Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231
Attention:  [·]
 
if to the Participant, to the address that the Participant most recently provided to the Company,
 
or to such other address or facsimile number as such party may hereafter specify for the purpose by notice to the other parties hereto.  All such notices, requests and other communications shall be deemed received on the date of receipt by the recipient thereof if received prior to 5:00 p.m. on a business day in the place of receipt.  Otherwise, any such notice, request or communication shall be deemed received on the next succeeding business day in the place of receipt.
 
(b)                                Entire Agreement.  This Agreement, the Plan and any other agreements, schedules, exhibits and other documents referred to herein or therein constitute the entire agreement and understanding between the parties in respect of the subject matter hereof and supersede all prior and contemporaneous arrangements, agreements and understandings, both oral and written, whether in term sheets, presentations or otherwise, between the parties with respect to the subject matter hereof.

(3)  Include if applicable.
 
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(c)                                 Amendment; Waiver.  No amendment or modification of any provision of this Agreement shall be effective unless signed in writing by or on behalf of the Company and the Participant, except that the Company may amend or modify this Agreement without the Participant’s consent in accordance with the provisions of the Plan or as otherwise set forth in this Agreement.  No waiver of any breach or condition of this Agreement shall be deemed to be a waiver of any other or subsequent breach or condition whether of like or different nature.  Any amendment or modification of or to any provision of this Agreement, or any waiver of any provision of this Agreement, shall be effective only in the specific instance and for the specific purpose for which made or given.
 
(d)                                Assignment.  Neither this Agreement nor any right, remedy, obligation or liability arising hereunder or by reason hereof shall be assignable by the Participant.
 
(e)                                 Successors and Assigns; No Third Party Beneficiaries.  This Agreement shall inure to the benefit of and be binding upon the Company and the Participant and their respective heirs, successors, legal representatives and permitted assigns.  Nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Company and the Participant, and their respective heirs, successors, legal representatives and permitted assigns, any rights, remedies, obligations or liabilities under or by reason of this Agreement.
 
(f)                                  Counterparts.  This Agreement may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
 
(g)                                 Participant Undertaking.  The Participant agrees to take whatever additional action and execute whatever additional documents the Company may deem necessary or advisable to carry out or give effect to any of the obligations or restrictions imposed on either the Participant or the RSUs pursuant to the provisions of this Agreement.
 
(h)                                Plan.  The Participant acknowledges and understands that material definitions and provisions concerning the RSUs and the Participant’s rights and obligations with respect thereto are set forth in the Plan.  The Participant has read carefully, and understands, the provisions of the Plan.
 
(i)                                    Dispute Resolution.  If any dispute arising out of or relating to this Agreement or the Plan, or the breach thereof, cannot be settled through negotiation, the parties agree first to try in good faith to settle such dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules.  If the parties fail to settle such dispute within 30 days after the commencement of such mediation, such dispute shall be settled by arbitration administered by the American Arbitration Association under its Commercial Arbitration Rules, and judgment on the arbitral award rendered may be entered in any court having jurisdiction thereof.
 
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IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first written above.
 
 	KOSMOS ENERGY LTD.	

 	By:	 	
 	 	Name:	
 	 	Title:	

 	 	[Name of Participant]	
 
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EXHIBIT 10.53
 
KOSMOS ENERGY LTD.
[AMENDED AND RESTATED] LONG TERM INCENTIVE PLAN
 
RSU Award Agreement
[Performance Vesting]
 
You have been granted a restricted share unit award (this “Award”) on the following terms and subject to the provisions of Attachments A and B and the Kosmos Energy Ltd. [Amended and Restated] Long Term Incentive Plan (the “ Plan ”).  Unless defined in this Award agreement (including Attachments A and B, this “ Agreement ”), capitalized terms will have the meanings assigned to them in the Plan.  In the event of a conflict among the provisions of the Plan, this Agreement and any descriptive materials provided to you, the provisions of the Plan will prevail.
 
Participant	 	[Full name] (the “Participant”)	
 	 	 	
Number of Restricted Share Units	 	[·] Restricted Share Units (the “RSUs” or “Restricted Share Units”), if 100% of the Performance Condition (as defined below) is satisfied (the “ Target RSUs ”)	
 	 	 	
Grant Date	 	[·] (the “Grant Date”)	
 	 	 	
Vesting	 	Subject to Section 3 of Attachment A, the RSUs shall vest to the extent that both the applicable “Service Condition” and the applicable “Performance Condition” (as such terms are defined below) with respect to such RSUs are satisfied.	
 	 	 	
Service Condition	 	Subject to Section 3 of Attachment A, the “Service Condition” shall be satisfied [insert applicable date(s)], in each case if the Participant does not experience a Termination of Service at any time prior to [such] [the applicable] date.	
 	 	 	
Performance Condition	 	Subject to Section 3 of Attachment A, the “Performance Condition” shall be deemed satisfied with respect to between 0% and 200% of the RSUs based on attainment of Relative TSR as of the End Date as detailed in Attachment B.	

 
Attachment A
 
RSU Award Agreement
Terms and Conditions
 
Grant to:  [Full name]
 
Section 1.  Grant of RSU Award.  Subject to the terms and conditions of the Plan and this Agreement, the Company hereby grants this Award to the Participant on the Grant Date on the terms set forth on the cover page of this Agreement, as more fully described in this Attachment A and in Attachment B.  This Award is granted under the Plan, which is incorporated herein by this reference and made a part of this Agreement.
 
Section 2.  Issuance of RSUs.
 
(a)                                Issuance. Each RSU shall represent the right to receive up to 200% of a Share upon the vesting of such RSU as determined in accordance with this Agreement.
 
(b)                                Voting Rights.  The Participant shall have no voting rights with respect to the RSUs unless and until the Participant becomes the record owner of the Shares, including Dividend Shares (as defined below) to the extent applicable, underlying such RSUs.
 
(c)                                 Dividend Equivalents. If a dividend is paid on Shares during the period commencing on the Grant Date and ending on the date on which the Shares underlying RSUs are distributed to the Participant, the Participant shall be eligible to receive an amount equal to the amount of the dividend that the Participant would have received had the Shares underlying the RSUs been distributed to the Participant as of the time at which such dividend is paid;  it being understood  that no such amount shall be payable with respect to any RSUs that are forfeited.  Such amount shall be paid to the Participant on the date on which the Shares underlying the RSUs are distributed to the Participant in the same form (cash, Shares or other property) in which such dividend is paid to holders of Shares generally.  Any Shares that the Participant is eligible to receive pursuant to this Section 2 are referred to herein as “ Dividend Shares .”
 
(d)                                Transferability.  The RSUs shall not be assigned, sold, transferred or otherwise be subject to alienation by the Participant.  Any assignment, sale, transfer or other alienation with respect to the Shares issuable upon the vesting of the RSUs shall be in accordance with applicable securities laws.
 
(e)                                 Withholding Requirements.  The Company may withhold any tax (or other governmental obligation) that becomes due with respect to the RSUs (or any dividend or distribution thereon), and the Participant shall make arrangements satisfactory to the Company to enable the Company to satisfy all such
 
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withholding requirements.  Notwithstanding the foregoing, the Committee, in its sole discretion, may permit the Participant to satisfy any such withholding requirement by transferring to the Company pursuant to such procedures as the Committee may require, effective as of the date on which such requirement arises, a number of vested Shares owned and designated by the Participant having an aggregate Fair Market Value as of such date that is equal to the minimum amount required to be withheld.  If the Committee permits the Participant to satisfy any such withholding requirement pursuant to the preceding sentence, the Company shall remit to the Internal Revenue Service and appropriate state and local revenue agencies, for the credit of the Participant, an amount of cash withholding equal to the Fair Market Value of the Shares transferred to the Company as provided above.
 
Section 3.  Accelerated Vesting, Forfeiture and Distribution.
 
(a)                                Termination of Service.
 
(i)                                    Death or Disability.  In the event of the Participant’s Termination of Service at any time due to the Participant’s death or Disability, the Service Condition shall be deemed fully satisfied as of such termination; provided  that, if such termination occurs prior to the End Date, then, subject to Section 3(b), the RSUs shall remain subject to the Performance Condition.
 
(ii)                                 Without Cause or for Good Reason.  In the event of the Participant’s Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason [[Option 1: the Service Condition shall be deemed fully satisfied as of such termination;  provided  that, if such termination occurs prior to the End Date, then, subject to Section 3(b), the RSUs shall remain subject to the Performance Condition] [Option 2: and other than as described in Section 3(b) below, (x) the RSUs, if any, for which the applicable Service Condition is satisfied as of such termination shall remain subject to the Performance Condition (if such termination occurs at any time prior to the End Date) and (y) the RSUs, if any, for which the applicable Service Condition is not satisfied as of such termination shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the RSUs at their par value]] (1) .

(1)  Include Option 1 or Option 2, as applicable.
 
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(iii)                              Without Good Reason.  In the event of the Participant’s Termination of Service by the Participant without Good Reason at any time prior to the End Date, (x) the RSUs, if any, for which the applicable Service Condition is satisfied as of such termination shall remain subject to the Performance Condition and (y) the RSUs, if any, for which the applicable Service Condition is not satisfied as of such termination shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the RSUs at their par value.
 
(iv)                             For Cause.  In the event of the Participant’s Termination of Service at any time by the Company or any Affiliate for Cause, the RSUs shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the RSUs at their par value.
 
(b)                                [Replacement of Award on] Change in Control.
 
[(i)                                If a Change in Control occurs and the Participant does not experience a Termination of Service at any time prior to such Change in Control, the Performance Condition shall be deemed satisfied at 100% as of the date of such Change in Control and, following such Change in Control, (x) [insert applicable fraction] of the Target RSUs will vest in the event that any anniversary of [the Grant Date] [insert applicable vesting commencement date] occurs during the first year after such Change in Control, and (y) all of the remaining Target RSUs will fully vest on the earlier of (A) [insert applicable vesting date], if the Participant does not experience a Termination of Service at any time prior to such date, and (B) the Participant’s Termination of Service due to the Participant’s death or Disability, by the Company or any Affiliate without Cause or by the Participant for Good Reason.]
 
[In the event of a Change in Control, this Award shall cease to represent the right to receive Shares and shall instead represent the right to receive Pubco Shares (as defined below) or cash, as follows:
 
(i)                                    If, as of immediately following such Change in Control, the shares of the surviving or resulting entity (or the direct or indirect parent of such entity) in such Change in Control are quoted or traded on a stock market or exchange (“ Pubco Shares ”), this Award shall represent the right to receive, upon the vesting thereof, a number of Pubco Shares having an aggregate Fair Market Value as of immediately following such Change in Control that is equal to the aggregate Fair Market Value of the Shares underlying this Award as of immediately prior to such Change in Control.
 
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(ii)                                 If, as of immediately following such Change in Control, the shares of the surviving or resulting entity (or the direct or indirect parent of such entity) in such Change in Control are not quoted or traded on a stock market or exchange, this Award shall represent the right to receive, upon the vesting thereof, an amount in cash equal to the aggregate Fair Market Value of the Shares underlying this Award as of immediately prior to such Change in Control.]
 
[[(ii)][(iii)]  [Notwithstanding Section 3(b)(i),] in the event of the Participant’s Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason during the period beginning three months prior to and ending one year after the date on which a Change in Control occurs, the RSUs that have not vested as of the date of such Termination of Service shall fully vest (i.e., the Service Condition shall be deemed fully satisfied, and the Performance Condition shall be deemed to have been satisfied as of 200% as of the date of such Change in Control) as of the later of (x) the date of such Termination of Service and (y) the date on which such Change in Control occurs; provided ,  however , that if such Termination of Service occurs during the three-month period prior to the date on which such Change in Control occurs, such full vesting of the RSUs shall only apply if such Termination of Service was at the request of a third party that has taken steps reasonably calculated to effectuate such Change in Control or that otherwise arose in connection with or anticipation of such Change in Control.  For the avoidance of doubt, if such Termination of Service occurs during the three-month period prior to the date on which such Change in Control occurs and such Termination of Service was not at the request of a third party that has taken steps reasonably calculated to effectuate such Change in Control or did not otherwise arise in connection with or anticipation of such Change in Control, the RSUs that have not vested as of the date of such Termination of Service shall be treated in accordance with Section 3(a)(ii).] (2)
 
[[(iii)                      In the event that, upon such Change in Control or within [insert applicable date] thereafter, the Participant experiences a Termination of Service by the Company or any Affiliate without Cause or by the Participant for Good Reason, this Award shall fully vest.] (3)
 
(iv)                             Following such Change in Control, this Award shall remain subject to the terms set forth in this Agreement (including the vesting, forfeiture and distribution provisions herein), as modified by this Section 3(b).]

(2)  For Andrew G. Inglis, the Chief Executive Officer of the Company.
 
(3)  For executive officers other than Mr. Inglis.
 
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(c)                                 Distribution on Vesting.  Subject to the provisions of this Agreement, upon the vesting of any of the RSUs, the Company shall distribute to the Participant, on or within 30 days after the date of such vesting, a number of Shares for each such RSU determined in accordance with Attachment B and, to the extent applicable, the number of Dividend Shares determined in accordance with Section 2(c) of this Attachment A [(such Shares and, if applicable, such Dividend Shares, collectively, the “ Maximum Shares ”). Notwithstanding the foregoing, if the Maximum Shares exceeds the number of Shares underlying the Target RSUs (the number of Shares equal to such excess, the “ Above Target Shares ”), in lieu of distributing to the Participant the entire amount of the Maximum Shares, the Committee, in its sole discretion, may determine to pay or distribute, as applicable, to the Participant, on or within 30 days after the date of such vesting, (i) an amount in cash equal to the aggregate Fair Market Value, as of the date of such vesting, of all or any number of the Above Target Shares, as determined by the Committee, and (ii) a number of Shares equal to the Maximum Shares less the number of the Above Target Shares in lieu of which the Participant received a cash payment pursuant to clause (i).] (4)  Subject to any applicable Lock Up Agreement, on such distribution, any Shares (including Dividend Shares) delivered to the Participant pursuant to this Section 3(c) shall be fully assignable, saleable and transferable by the Participant, and the Company shall deliver such Shares to the Participant by transfer or issuance to the Depository Trust Company for the benefit of the Participant or by delivery of a share certificate registered in the Participant’s name and such transfer or issuance shall be evidenced in the register of members of the Company.
 
[(d)                            Effect of Failure to Obtain Shareholder Approval of the Plan.  Notwithstanding anything in this Agreement to the contrary, if, as of the date on which any of the RSUs vest, the Company’s shareholders have not approved the Plan, as amended by the Board on January 23, 2015, the Company shall pay to the Participant, in lieu of the Shares (including any Dividend Shares) that would otherwise have been distributed to the Participant pursuant to Section 3(c) (assuming for such purpose that the Committee did not exercise its discretion pursuant to Section 3(c)(i) to pay the Participant cash in lieu of any Above Target Shares), on or within 30 days after such vesting date, an amount in cash equal to the aggregate Fair Market Value, as of such vesting date, of such Shares.] (5)
 
(e)                                 Effect of Failure to Achieve Performance Condition.  On the End Date, any of the RSUs for which the Performance Condition is not satisfied as of such date shall be forfeited without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the RSUs at their par value.

(4)  Include if applicable.
 
(5)  Include if applicable.
 
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Section 4.  Miscellaneous Provisions.
 
(a)                                Notices.  All notices, requests and other communications under this Agreement shall be in writing and shall be delivered in person (by courier or otherwise), mailed by certified or registered mail, return receipt requested, or sent by facsimile transmission, as follows:
 
if to the Company, to:
 
Kosmos Energy Ltd.
c/o Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231
Attention:  [·]
 
if to the Participant, to the address that the Participant most recently provided to the Company,
 
or to such other address or facsimile number as such party may hereafter specify for the purpose by notice to the other parties hereto.  All such notices, requests and other communications shall be deemed received on the date of receipt by the recipient thereof if received prior to 5:00 p.m. on a business day in the place of receipt.  Otherwise, any such notice, request or communication shall be deemed received on the next succeeding business day in the place of receipt.
 
(b)                                Entire Agreement.  This Agreement, the Plan and any other agreements, schedules, exhibits and other documents referred to herein or therein constitute the entire agreement and understanding between the parties in respect of the subject matter hereof and supersede all prior and contemporaneous arrangements, agreements and understandings, both oral and written, whether in term sheets, presentations or otherwise, between the parties with respect to the subject matter hereof.
 
(c)                                 Amendment; Waiver.  No amendment or modification of any provision of this Agreement shall be effective unless signed in writing by or on behalf of the Company and the Participant, except that the Company may amend or modify this Agreement without the Participant’s consent in accordance with the provisions of the Plan or as otherwise set forth in this Agreement.  No waiver of any breach or condition of this Agreement shall be deemed to be a waiver of any other or subsequent breach or condition whether of like or different nature.  Any amendment or modification of or to any provision of this Agreement, or any waiver of any provision of this Agreement, shall be effective only in the specific instance and for the specific purpose for which made or given.
 
A-6

 
(d)                                Assignment.  Neither this Agreement nor any right, remedy, obligation or liability arising hereunder or by reason hereof shall be assignable by the Participant.
 
(e)                                 Successors and Assigns; No Third Party Beneficiaries.  This Agreement shall inure to the benefit of and be binding upon the Company and the Participant and their respective heirs, successors, legal representatives and permitted assigns.  Nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Company and the Participant, and their respective heirs, successors, legal representatives and permitted assigns, any rights, remedies, obligations or liabilities under or by reason of this Agreement.
 
(f)                                  Counterparts.  This Agreement may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
 
(g)                                 Participant Undertaking.  The Participant agrees to take whatever additional action and execute whatever additional documents the Company may deem necessary or advisable to carry out or give effect to any of the obligations or restrictions imposed on either the Participant or the RSUs pursuant to the provisions of this Agreement.
 
(h)                                Plan.  The Participant acknowledges and understands that material definitions and provisions concerning the RSUs and the Participant’s rights and obligations with respect thereto are set forth in the Plan.  The Participant has read carefully, and understands, the provisions of the Plan.
 
(i)                                    Dispute Resolution.  If any dispute arising out of or relating to this Agreement or the Plan, or the breach thereof, cannot be settled through negotiation, the parties agree first to try in good faith to settle such dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules.  If the parties fail to settle such dispute within 30 days after the commencement of such mediation, such dispute shall be settled by arbitration administered by the American Arbitration Association under its Commercial Arbitration Rules, and judgment on the arbitral award rendered may be entered in any court having jurisdiction thereof.
 
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IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first written above.

 	KOSMOS ENERGY LTD.	

 	By:	 	
 	 	 	 	
 	 	Name:	 	
 	 	Title:	 	

 	 	 	
 	 	[Name of Participant]	
 
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Attachment B
 
Performance Condition
 
Section 1.  Definitions.  As used in this Attachment B, the following terms shall have the meanings set forth below:
 
(a)                                “End Date” means [·].
 
(b)                                “End Price” with respect to a Share or a Peer Share means the average of the closing price of such Share or Peer Share on each of the [ · ] trading days ending with the End Date on the applicable Principal Exchange; provided  that, if such Principal Exchange is a non-U.S. stock market or exchange, each such closing price shall be converted to U.S. dollars at the applicable spot exchange rate as of such trading day;  provided further  that the Committee shall adjust equitably the End Price with respect to such Share or Peer Share, as calculated in accordance with the preceding clause, to reflect any corporate transaction or event set forth in Section 5(c) of the Plan that affects such Share or Peer Share if such adjustment is appropriate to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under this Award.
 
(c)                                 “Grant Year” means the year in which the Grant Date occurs.
 
(d)                                “Peer” means any of the following companies whose shares are quoted or traded on the End Date on a Principal Exchange: [Africa Oil Corp.,] Anadarko Petroleum Corporation, [Apache Corporation,] BG Group plc, Cairn Energy plc, Cobalt International Energy, Inc., [Genel Energy plc,] [HRT Participacoes em Petroleo SA,] Lundin Petroleum AB, Noble Energy, Inc., [Ophir Energy plc,] Premier Oil plc [,][and] Tullow Oil plc [and] [insert additional peer companies, if applicable].
 
(e)                                 “Peer Share” means the share of a Peer that is quoted or traded on  a national securities exchange.
 
(f)                                  “Principal Exchange” means the principal U.S. securities exchange or non-U.S. stock market or exchange on which a Share or Peer Share is quoted or traded as of an applicable date.  For the avoidance of doubt, a Share or Peer Share that is quoted or traded only over the counter shall not be deemed to be quoted or traded on a Principal Exchange.
 
(g)                                 “Relative TSR” means the percentile ranking of the TSR of a Share in relation to the TSR of each of the Peers’ Shares, as calculated by the Committee in good faith applying a reasonable statistical method.
 
(h)                                “Start Date” means [·].
 
B-1

 
(i)                                    “Start Price” with respect to a Share or a Peer Share means the average of the closing price of such Share or Peer Share on each of the [ · ] trading days ending with the Start Date on the applicable Principal Exchange; provided  that, if such Principal Exchange is a non-U.S. stock market or exchange, such closing price shall be converted to U.S. dollars at the applicable spot exchange rate on such date;  provided further  that the Committee shall adjust equitably the Start Price with respect to such Share or Peer Share, as calculated in accordance with the preceding clause, to reflect any corporate transaction or event set forth in Section 5(c) of the Plan that affects such Share or Peer Share if such adjustment is appropriate to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under this Award.
 
(j)                                   “TSR” with respect to a Share or Peer Share means (i) the sum of (x) the End Price of such Share or Peer Share minus the Start Price of such Share or Peer Share and (y) the aggregate amount of the dividends, if any, paid on such Share or Peer Share for any dividend record dates that occur during the period beginning on the Start Date and ending on the End Date, divided by (ii) such Start Price.
 
Section 2.  Performance Condition Attainment.
 
[Insert table setting forth the percentage (between 0% and 200%) of an RSU for which the Performance Condition shall be deemed satisfied based on the percentile attainment of Relative TSR (between 0 and 100) indicated in the corresponding row of the table]
 
For the avoidance of doubt, to the extent that the total number of Shares (including Dividend Shares, to the extent applicable) eligible to be distributed to the Participant upon vesting of the RSUs pursuant to this Award would otherwise result in the issuance of a fractional Share, such fractional Share shall be cancelled in exchange for a cash payment therefor.
 
B-2

EXHIBIT 10.54
 
KOSMOS ENERGY LTD.
[AMENDED AND RESTATED] LONG TERM INCENTIVE PLAN
 
RSU Award Agreement
[Directors—Service Vesting]
 
You have been granted a restricted share unit award (this “Award”) on the following terms and subject to the provisions of Attachment A and the Kosmos Energy Ltd. [Amended and Restated] Long Term Incentive Plan (the “ Plan ”).  Unless defined in this Award agreement (including Attachment A, this “ Agreement ”), capitalized terms will have the meanings assigned to them in the Plan.  In the event of a conflict among the provisions of the Plan, this Agreement and any descriptive materials provided to you, the provisions of the Plan will prevail.
 
Participant	 	[Full Name]	
 	 	 	
Number of Restricted Share Units	 	[·] Restricted Share Units (the “RSUs” or “Restricted Share Units ”)	
 	 	 	
Grant Date	 	[·] (the “Grant Date”)	
 	 	 	
Vesting	 	Subject to Section 3 of Attachment A, the RSUs shall vest on [insert applicable vesting date[s]] if the Participant does not experience a Termination of Service at any time prior to [such] [the applicable] vesting date. [Further, subject to Section 3 of Attachment A, if a Change in Control occurs, then the RSUs that have not vested pursuant to the preceding sentence shall fully vest on [insert date].]	

 
Attachment A
 
RSU Award Agreement
Terms and Conditions
 
Grant to: [Full Name]
 
Section 1.  Grant of RSU Award.  Subject to the terms and conditions of the Plan and this Agreement, the Company hereby grants this Award to the Participant on the Grant Date on the terms set forth on the cover page of this Agreement, as more fully described in this Attachment A.  This Award is granted under the Plan, which is incorporated herein by this reference and made a part of this Agreement.
 
Section 2.  Issuance of RSUs.
 
(a)                                Issuance. Each RSU shall represent the right to receive one Share upon the vesting of such RSU in accordance with this Agreement.
 
(b)                                Voting Rights.  The Participant shall have no voting rights with respect to the RSUs unless and until the Participant becomes the record owner of the Shares, including Dividend Shares (as defined below) to the extent applicable, underlying such RSUs.
 
(c)                                 Dividend Equivalents. If a dividend is paid on Shares during the period commencing on the Grant Date and ending on the date on which the Shares underlying RSUs are distributed to the Participant, the Participant shall be eligible to receive an amount equal to the amount of the dividend that the Participant would have received had the Shares underlying the RSUs been distributed to the Participant as of the time at which such dividend is paid;  it being understood  that no such amount shall be payable with respect to any RSUs that are forfeited.  Such amount shall be paid to the Participant on the date on which the Shares underlying the RSUs are distributed to the Participant in the same form (cash, Shares or other property) in which such dividend is paid to holders of Shares generally.  Any Shares that the Participant is eligible to receive pursuant to this Section 2 are referred to herein as “ Dividend Shares .”
 
(d)                                Transferability.  The RSUs shall not be assigned, sold, transferred or otherwise be subject to alienation by the Participant.  Any assignment, sale, transfer or other alienation with respect to the Shares issuable upon the vesting of the RSUs shall be in accordance with applicable securities laws.
 
(e)                                 Withholding Requirements.  The Company may withhold any tax (or other governmental obligation) that becomes due with respect to the RSUs (or any dividend or distribution thereon), and the Participant shall make arrangements satisfactory to the Company to enable the Company to satisfy all such
 
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withholding requirements. Notwithstanding the foregoing, the Committee, in its sole discretion, may permit the Participant to satisfy any such withholding requirement by transferring to the Company pursuant to such procedures as the Committee may require, effective as of the date on which such requirement arises, a number of vested Shares owned and designated by the Participant having an aggregate Fair Market Value as of such date that is equal to the minimum amount required to be withheld.  If the Committee permits the Participant to satisfy any such withholding requirement pursuant to the preceding sentence, the Company shall remit to the Internal Revenue Service and appropriate state and local revenue agencies, for the credit of the Participant, an amount of cash withholding equal to the Fair Market Value of the Shares transferred to the Company as provided above.
 
Section 3.  Accelerated Vesting, Forfeiture upon Termination of Service and Distribution.
 
(a)                                Death or Disability.  In the event of the Participant’s Termination of Service at any time due to the Participant’s death or Disability, the RSUs shall fully vest as of the date of such Termination of Service.
 
[(b)                            For Cause. In the event of the Participant’s Termination of Service at any time for cause (as defined in the Company’s Bye Laws, as may be amended from time to time), any unvested RSUs shall be forfeited in their entirety without any payment to the Participant, or in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the RSUs at their par value.]
 
[(b)][(c)]  For Any Other Reason.  In the event of the Participant’s Termination of Service at any time under circumstances not described in Section 3(a) [or 3(b), (i) the portion of the RSUs that is scheduled to vest on the next applicable vesting date shall vest on the date of such Termination of Service and (ii) the portion of the RSUs that is not scheduled to vest in accordance with clause (i)] [, any unvested RSUs] shall be forfeited in their entirety without any payment to the Participant or, in the Committee’s sole discretion, if required pursuant to applicable law to effect such forfeiture, the Company may repurchase the RSUs at their par value.
 
[(c)][(d)]  Distribution on Vesting.  Subject to the provisions of this Agreement, upon the vesting of any of the RSUs, the Company shall distribute to the Participant, on or within 30 days after the date of such vesting, one Share for each such RSU and the number of Dividend Shares, if any, determined in accordance with Section 2(c) of this Attachment A.  Subject to any applicable Lock Up Agreement, on such distribution, such Shares (including Dividend Shares) shall be fully assignable, saleable and transferable by the Participant, and the Company shall deliver such Shares to the Participant by transfer or issuance to the Depository Trust Company for the benefit of the Participant or by delivery of
 
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a share certificate registered in the Participant’s name and such transfer or issuance shall be evidenced in the register of members of the Company.
 
Section 4.  Miscellaneous Provisions.
 
(a)                                Notices.  All notices, requests and other communications under this Agreement shall be in writing and shall be delivered in person (by courier or otherwise), mailed by certified or registered mail, return receipt requested, or sent by facsimile transmission, as follows:
 
if to the Company, to:
 
Kosmos Energy Ltd.
c/o Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231
Attention:  [·]
 
if to the Participant, to the address that the Participant most recently provided to the Company,
 
or to such other address or facsimile number as such party may hereafter specify for the purpose by notice to the other parties hereto.  All such notices, requests and other communications shall be deemed received on the date of receipt by the recipient thereof if received prior to 5:00 p.m. on a business day in the place of receipt.  Otherwise, any such notice, request or communication shall be deemed received on the next succeeding business day in the place of receipt.
 
(b)                                Entire Agreement.  This Agreement, the Plan and any other agreements, schedules, exhibits and other documents referred to herein or therein constitute the entire agreement and understanding between the parties in respect of the subject matter hereof and supersede all prior and contemporaneous arrangements, agreements and understandings, both oral and written, whether in term sheets, presentations or otherwise, between the parties with respect to the subject matter hereof.
 
(c)                                 Amendment; Waiver.  No amendment or modification of any provision of this Agreement shall be effective unless signed in writing by or on behalf of the Company and the Participant, except that the Company may amend or modify this Agreement without the Participant’s consent in accordance with the provisions of the Plan or as otherwise set forth in this Agreement.  No waiver of any breach or condition of this Agreement shall be deemed to be a waiver of any other or subsequent breach or condition whether of like or different nature.  Any amendment or modification of or to any provision of this Agreement, or any waiver of any provision of this Agreement, shall be effective only in the specific instance and for the specific purpose for which made or given.
 
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(d)                                Assignment.  Neither this Agreement nor any right, remedy, obligation or liability arising hereunder or by reason hereof shall be assignable by the Participant.
 
(e)                                 Successors and Assigns; No Third Party Beneficiaries.  This Agreement shall inure to the benefit of and be binding upon the Company and the Participant and their respective heirs, successors, legal representatives and permitted assigns.  Nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Company and the Participant, and their respective heirs, successors, legal representatives and permitted assigns, any rights, remedies, obligations or liabilities under or by reason of this Agreement.
 
(f)                                  Counterparts.  This Agreement may be signed in any number of counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
 
(g)                                 Participant Undertaking.  The Participant agrees to take whatever additional action and execute whatever additional documents the Company may deem necessary or advisable to carry out or give effect to any of the obligations or restrictions imposed on either the Participant or the RSUs pursuant to the provisions of this Agreement.
 
(h)                                Plan.  The Participant acknowledges and understands that material definitions and provisions concerning the RSUs and the Participant’s rights and obligations with respect thereto are set forth in the Plan.  The Participant has read carefully, and understands, the provisions of the Plan.
 
(i)                                    Dispute Resolution.  If any dispute arising out of or relating to this Agreement or the Plan, or the breach thereof, cannot be settled through negotiation, the parties agree first to try in good faith to settle such dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules.  If the parties fail to settle such dispute within 30 days after the commencement of such mediation, such dispute shall be settled by arbitration administered by the American Arbitration Association under its Commercial Arbitration Rules, and judgment on the arbitral award rendered may be entered in any court having jurisdiction thereof.
 
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IN WITNESS WHEREOF, the parties have executed this Agreement as of the day and year first written above.
 
 	KOSMOS ENERGY LTD.	

 	By:	 	

 	 	Name:	
 	 	Title:	

 	[Full Name]	
 
A-5

EXHIBIT 10.60

 
October 16, 2014
 
Tom Chambers
[ADDRESS]
[ADDRESS]
RE:  Offer of Employment:  Senior Vice President and Chief Financial Officer
 
Dear Tom:
 
On behalf of Kosmos Energy, LLC (the “Company”), I am pleased to extend this offer of employment (this “Offer”) to you in the position of Senior Vice President and Chief Financial Officer in accordance with the following terms:
 
Start Date:	 	On or before November 5, 2014 (the “Start Date”).	
 	 	 	
Base Salary:	 	Base salary at an initial annual rate of $550,000 (the “Base Salary”), payable in accordance with the Company’s payroll practices as in effect from time to time. The Company currently pays salary on the 15th and the last day of each month. The Company will review the Base Salary annually to determine whether to increase it. The Base Salary will not be decreased except in connection with a proportionate across-the-board decrease for the Company’s senior executives generally.	
 	 	 	
Annual Target Cash Bonus:	 	Annual discretionary cash bonus that will be targeted at 100% of the Base Salary (the “Target Bonus ”), based upon both Company and individual performance. The actual cash bonus, if any, that you would receive for any year based on the level of attainment of the applicable Company and individual performance metrics within the context of prevailing market conditions and may range between 0% and 200% of the Base Salary.	
 	 	 	
Sign-On Equity Awards:	 	On the first day of the calendar month following the Start Date, you will receive two awards (the “ Sign-On Equity Awards ”) of restricted share units (“ RSUs ”). The Sign-On Equity Awards will be issued under the Kosmos Energy Ltd. Long Term Incentive Plan (such plan, or any successor thereto, the “ LTIP ”), and will be subject to the terms (including, without limitation, the applicable vesting schedules and forfeiture restrictions) set forth in the LTIP and individual award agreements. The Sign-On Equity Awards will have an aggregate value as of the grant date of $1,650,000. Of this amount, $825,000 will be granted in the form of service-vesting RSUs and $825,000 will be granted in the form of performance-vesting RSUs. The number of common shares of Kosmos Energy	

 
 	 	Ltd. (“Kosmos”) underlying each Sign-On Equity Award (at target, in the case of the performance-vesting RSUs) will be determined in accordance with the terms of the LTIP by dividing the grant date value of such award by the closing price of a common share on the grant date.	
 	 	 	
Long Term Incentive (“LTI”) Opportunity	 	In addition to the Sign-On Equity Awards, during your employment with the Company you will be eligible for annual long-term incentive (“ LTI ”) equity awards. You will receive an initial award (the “ 2015 LTI Award ”) of RSUs with an aggregate value as of the grant date of $1,650,000 in 2015 as part of the LTIP award cycle which is expected to be granted by the end of June, 2015, assuming that you are still employed by the Company on the grant date that such awards are granted. The 2015 LTI Award will follow an allocation between service-vesting and performance vesting RSUs that is consistent with the other members of the Company’s senior management.	
 	 	 	
Severance Benefits:	 	If you are terminated through no fault of your own or your position is eliminated and you are not offered a comparable position in Dallas (other than in connection with a Change in Control as defined in the LTIP), then subject to: (i) your execution and non-revocation of a general release of claims provided by the Company; (ii) such release becoming effective not later than 60 days after such termination, and (iii) your continued compliance with any confidentiality covenants to which you are subject you will receive a severance payment equal to your then current Base Salary plus Target Bonus for 1 year. Additionally, the Company will reimburse you the amount of COBRA payments to cover medical and dental health insurance for you and your eligible dependents for 1 year.	
 	 	 	
Change in Control:	 	If your employment with the Company is terminated in connection with a Change in Control, you will generally be eligible for severance benefits under the Company’s Change in Control Severance Policy (the “ Severance Policy ”), subject to the terms of the Severance Policy. Notwithstanding the foregoing, the Company reserves the right to amend or terminate the Severance Policy at any time, with or without notice.	
 
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Relocation:	 	You will be required to relocate your principal residence to the Dallas/Fort Worth area as soon as practicable after the Start Date. The Company will pay or reimburse you for all reasonable and customary costs associated with the following:
 
·                 As discussed, we contemplate that you will continue to maintain your residence in Sugar Land, Texas and that you will commute between Sugar Land and Dallas for a period of up to twelve (12) months (the  “Transition Period.” ) During the Transition Period, the Company will cover your reasonable and necessary temporary housing expenses in the Dallas/Fort Worth area, as well as your costs of commuting between Sugar Land, Texas and Dallas, Texas.
 
In addition, after the Transition Period the Company will pay or reimburse you for the costs of the following items to facilitate your move from Sugar Land to Dallas:
 
·                 Packing and transporting standard furniture and personal household goods and effects belonging to you and members of your immediate family.
 
·                 Reasonable expenses, including travel, for you and members of your immediate family to obtain permanent housing in the Dallas/Fort Worth area.
 
·                 A one-time lump sum of $5,000 to cover miscellaneous expenses.
 
·                 Reimbursement of actual closing costs, realtor costs, inspection costs, and related costs associated with the sale of your existing home in Sugar Land, Texas and the purchase/lease of a new residence in the Dallas/Fort Worth area. You will be required to sell your existing home and either purchase or lease a home in the Dallas/Fort Worth area to receive this reimbursement.
 
The reimbursements made to you with respect to the foregoing relocation benefits shall include amounts intended to cover the U.S. tax obligations that you would expect to incur in relation to such relocation benefits.	
 	 	 	
401(k) Plan:	 	You will be eligible to participate in the Company’s 401(k) plan starting on your Start Date. Currently the Company matches employees’ contributions to the plan dollar for dollar up to the lesser of 8% of eligible compensation contributed or the applicable Internal Revenue Service maximum. The Company match is not guaranteed to remain at the same level. You will be notified if there is a plan contribution or design change.	
 	 	 	
Other Benefits:	 	You will be entitled to participate in the Company’s other benefit plans applicable to full-time regular employees. For the 2014 calendar year, the Company is paying 100% of the cost of such benefit plans. The Company reserves the right to change the benefits provided or the costs charged to employees at any time in its sole discretion;  provided ,  however , that the	
 
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 	 	Company will not decrease your benefits, or the portion of your benefits costs borne by the Company, except in connection with such an across- the-board decrease for the Company’s U.S.-based senior executives generally.	
 	 	 	
Vacation:	 	Based on your years of relevant industry-related work experience, the Company will provide with you with five weeks of annual vacation allowance (prorated for the first year of your employment based on the number of calendar days that you are employed in such year), in line with the Company’s other executive officers.	
 	 	 	
Spousal Assistance:	 	If required, the Company will provide employment assistance through The MI Group for your spouse. This benefit includes, but is not limited to, career counseling, employment search coaching, resume development, employment search assistance and career development workshops. The use of this benefit is required to be commenced within 90 days after your move date to Dallas and to be completed within one year after such move date.	
 	 	 	
Holidays:	 	The Company’s current practice is to provide employees with nine nationally recognized major U.S. holidays and up to two additional “floating” holidays of their choice. The Company reserves the right to change this general practice at any time in its sole discretion.	

 	Sincerely,	
 	 	
 	/s/ Andrew G. Inglis	
 	Andrew G. Inglis	
 	Chairman and Chief Executive Officer	

I agree to the terms of employment set forth above.  Furthermore, I represent to the Company that I am not subject to any obligation or agreement (including an employment agreement or non-compete agreement) that would prevent me from becoming an employee of the Company or that will adversely impact my ability to perform my duties.
 
/s/ Thomas P. Chambers	 	
Thomas P. Chambers	 	

October 13, 2014	 	
 
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Exhibit 21.1

List of Subsidiaries

Subsidiary	 	Jurisdiction of Incorporation	
Kosmos Energy Ltd. 	 	Bermuda	
Kosmos Energy Holdings	 	Cayman Islands	
Kosmos Energy LLC	 	Texas	
Kosmos Energy Operating	 	Cayman Islands	
Kosmos Energy Ventures	 	Cayman Islands	
Kosmos Energy South Atlantic	 	Cayman Islands	
Kosmos Energy Latin America	 	Cayman Islands	
Kosmos Energy Brasil Oleo e Gas Ltda. 	 	Brazil	
Kosmos Energy Deepwater Morocco	 	Cayman Islands	
Kosmos Energy Cameroon HC	 	Cayman Islands	
Kosmos Energy Offshore Morocco HC	 	Cayman Islands	
Kosmos Energy Finance International	 	Cayman Islands	
Kosmos Energy Finance	 	Cayman Islands	
Kosmos Energy International	 	Cayman Islands	
Kosmos Energy Development	 	Cayman Islands	
Kosmos Energy Ghana HC	 	Cayman Islands	
Kosmos Energy Suriname	 	Cayman Islands	
Kosmos Energy Ireland	 	Cayman Islands	
Kosmos Energy Mauritani	 	Cayman Islands	
Kosmos Energy Sierra Leone	 	Cayman Islands	
Kosmos Energy Equatorial Guinea	 	Cayman Islands	
Kosmos Energy Credit International	 	Cayman Islands	
FATE Energy Services	 	Cayman Islands	
Kosmos Energy Operating Service SARL	 	Morocco	
Kosmos Energy Liberia	 	Cayman Islands	
Kosmos Energy Portugal	 	Cayman Islands	
Kosmos Energy Senegal	 	Cayman Islands	

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Exhibit 21.1
List of Subsidiaries

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Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

        We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-174234) pertaining to the Kosmos Energy Ltd. Long Term Incentive Plan and the Registration Statement (Form S-3 No. 333-182280) of Kosmos Energy Ltd. and in the related Prospectus of our reports dated February 23, 2015, with respect to the consolidated financial statements and schedules and the effectiveness of internal control over financial reporting of Kosmos Energy Ltd., included in this Annual Report (Form 10-K) for the year ended December 31, 2014.
 	 	 	
 	 	/s/ Ernst & Young LLP	
Dallas, Texas
February 23, 2015

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Exhibit 23.1
Consent of Independent Registered Public Accounting Firm

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Exhibit 23.2

 	 	 	
 	 	February 13, 2015	

Mr. Eric Haas
Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231	

        We hereby consent to (1) the reference of our firm and to the use of our reports of the Jubilee Field and TEN Project Area effective December 31, 2014 and dated January 15, 2015, in the Kosmos Energy Ltd. Annual Report on Form 10-K for the year ended December 31, 2014, to be filed with the U.S. Securities Exchange Commission on or about February 24, 2015; and (2) the incorporation by reference of our reports of the Jubilee Field and TEN Project Area effective December 31, 2014 and dated January 15, 2015 in the Kosmos Energy Ltd. Registration Statement (Form S-8, No. 333-174234) and Registration Statement (Form S-3, No. 333-182280) and in any related prospectus, including any reference to our firm under the heading "Experts" in such prospectus.

RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580	

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Exhibit 23.2

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Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

        We hereby consent to the reference of our firm and to the use of our reports effective December 31, 2013 and December 31, 2012, dated January 15, 2014 and January 28, 2013, respectively, in the Kosmos Energy Ltd. Annual Report on Form 10-K for the year ended December 31, 2014, to be filed with the U. S. Securities and Exchange Commission on or about February 16, 2015.
 	 	 	 	 	
 	 	NETHERLAND, SEWELL & ASSOCIATES, INC.	

 	
By:	
 	
/s/ C.H. (SCOTT) REES III

C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer	
Dallas, Texas
February 16, 2015

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

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Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

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Exhibit 31.1

Certification of Chief Executive Officer

I, Andrew G. Inglis, certify that:1.
I have reviewed this annual report on Form 10-K of Kosmos Energy Ltd.;

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

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

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

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

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

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

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

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

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

(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
 	 	 	
Date: February 23, 2015	 	/s/ ANDREW G. INGLIS

Andrew G. Inglis
Chairman of the Board of Directors and
Chief Executive Officer (Principal Executive Officer)	

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Exhibit 31.1
Certification of Chief Executive Officer

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Exhibit 31.2

Certification of Chief Financial Officer

I, Thomas P. Chambers, certify that:1.
I have reviewed this annual report on Form 10-K of Kosmos Energy Ltd.;

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

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

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

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

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

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

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

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

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

(b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
 	 	 	
Date: February 23, 2015	 	/s/ THOMAS P. CHAMBERS

Thomas P. Chambers
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)	

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Exhibit 31.2
Certification of Chief Financial Officer

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Exhibit 32.1

Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the accompanying annual report of Kosmos Energy Ltd. (the "Company") on Form 10-K for the period ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Andrew G. Inglis, Chairman of the Board of Directors and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 	 	 	
Date: February 23, 2014	 	/s/ ANDREW G. INGLIS

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

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Exhibit 32.1
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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Exhibit 32.2

Certification of Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the annual report of Kosmos Energy Ltd. (the "Company") on Form 10-K for the period ended December 31, 2014, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Thomas P. Chambers, Senior Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 	 	 	
Date: February 23, 2015	 	/s/ THOMAS P. CHAMBERS

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

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Exhibit 32.2
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Exhibit 99.1
 
 	 	HOUSTON, TEXAS 77002-5294	 	FAX (713) 651-0849
TELEPHONE (713) 651-9191	
 
 	January 15, 2015	
 
Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231
 
Gentlemen:
 
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain interests of Kosmos Energy, LLC (Kosmos) as of December 31, 2014. The subject properties are located in the country of Ghana offshore West Africa in the West Cape Three Points (WCTP) and Deep Water Tano (DWT) blocks, hereafter referred to as “Jubilee Project Area”. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 15, 2015 and presented herein, was prepared for public disclosure by Kosmos in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
 
The properties evaluated by Ryder Scott in this report represent 64 percent of the total net proved liquid hydrocarbon reserves and 61 percent of the total net proved gas reserves of Kosmos as of December 31, 2014.
 
The estimated reserves and future net income amounts presented in this report, as of December 31, 2014, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to December 31, 2014, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.
 
SUITE 600, 1015 4TH STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790	
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258	

 
SEC PARAMETERS
Estimated Net Reserves and Income Data
Derived Through Certain Interest in the Jubilee Project Area
Kosmos Energy, LLC
As of December 31, 2014
 
 	 	Proved	 	
 	 	Developed	 	 	 	Total	 	
 	 	Producing	 	Undeveloped	 	Proved	 	
Net Remaining Reserves	 	 	 	 	 	 	 	
Oil/Condensate — MBarrels	 	43,413	 	3,267	 	46,680	 	
Fuel Gas — MMCF	 	8,616	 	0	 	8,616	 	
Income Data (M$)	 	 	 	 	 	 	 	
Future Gross Revenue	 	$	4,408,560	 	$	331,764	 	$	4,740,324	 	
Deductions	 	958,032	 	57,336	 	1,015,368	 	
Future Net Income (FNI)	 	$	3,450,528	 	$	274,428	 	$	3,724,956	 	
Discounted FNI @ 10% Before Taxes	 	$	2,620,117	 	$	196,400	 	$	2,816,517	 	
Discounted FNI @ 10% After Taxes	 	$	1,793,791	 	$	133,606	 	$	1,927,397	 	
 
Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are attributed to those volumes of gas that are consumed for fuel in field operations and are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).
 
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PalantirCASH, a copyrighted product of Palantir Solutions. The program was used at the request of Kosmos. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
 
The deductions include the normal direct costs of operating the wells and facilities, development costs, certain abandonment costs net of salvage, and Additional Oil Entitlements (“AOE”). AOE is a contractual mechanism that prevents the contractor group from collecting “windfall profits” and is treated herein as a deduction to the future gross revenue; however, for the Jubilee Project Area our economic analysis indicates no AOE deductions for the proved reserves. There are no production taxes associated with the Jubilee Project Area. The Discounted FNI @ 10% Before Taxes shown above does not include deductions for corporate income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. This FNI value was then adjusted by deducting corporate income taxes and the result is shown above as “Future Net Income @ 10% After Taxes”. The AOE calculation is determined at the block level and includes a rate of return calculation that is derived on an after corporate income tax basis based on interpretations of tax considerations made by Kosmos. All deductions pertaining to operating expenses, depletion, abandonment and royalties that were applied towards the calculation of corporate income taxes are strictly related to the Jubilee contract area. There are no corporate income tax deductions for the AOE calculation that are related to expenditures, royalties, or any other deductible items outside of the Jubilee contract area. Liquid hydrocarbon reserves account for 100 percent of the total future gross revenue from proved reserves.
 
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The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded annually. These results are presented for your information and should not be construed as our estimate of fair market value.
 
Reserves Included in This Report
 
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
 
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.
 
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Kosmos request, this report addresses only the proved reserves attributable to the properties evaluated herein.
 
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
 
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
 
The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production. Furthermore, the subject properties located in Ghana may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Kosmos for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Kosmos the net economic benefit attributed to such operations for the determination of
 
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the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Kosmos representations regarding such contractual information should be construed as a legal opinion on this matter.
 
Ryder Scott did not evaluate the country and geopolitical risks in the country of Ghana, where Kosmos operates or has interests. Kosmos operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
 
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Kosmos owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
 
Estimates of Reserves
 
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
 
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding
 
4

 
proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
 
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
 
The proved reserves for the properties included herein were estimated by a combination of performance methods, analogy and the volumetric methods. One hundred percent (100%) of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by a combination of methods. The performance methods include, but may not be limited to, reservoir simulation, which utilized extrapolations of historical production and pressure data available through October 31, 2014 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Kosmos and were considered sufficient for the purpose thereof.
 
One hundred percent (100%) of the proved undeveloped reserves included herein were estimated by a combination of the volumetric method and analogy. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Kosmos. The data utilized from the well and seismic data incorporated into our volumetric analysis were provided by Kosmos and were considered sufficient for the purpose thereof.
 
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
 
Kosmos has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Kosmos with respect to property interests and contractual terms that govern future net income, production and well tests from examined wells, normal direct costs of operating the Jubilee Project Area and all the required facilities such as the FPSO, other costs such as transportation and/or processing fees, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Kosmos. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
 
5

 
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
 
Future Production Rates
 
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
 
Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Kosmos. Wells or locations may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
 
The future production rates from the subject wells and locations may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
 
Hydrocarbon Prices
 
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to December 31, 2014, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. All the proved volumes projected herein are forecast to be recovered prior to contract expiration.
 
Kosmos furnished us with the above mentioned average prices in effect on December 31, 2014. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in this report.
 
6

 
The product prices that were actually used to determine the future gross revenue for the subject property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Kosmos. In the case of the Jubilee Project Area, Kosmos has estimated that the applicable differential is $0.25/bbl. The differential furnished to us was accepted as factual data and reviewed by us for its reasonableness; however, we have not conducted an independent verification of the data used by Kosmos to determine this differential.
 
In addition, the table below summarizes the net volume weighted benchmark price adjusted for differential and referred to herein as the “average realized price.” The average realized price shown in the table below was determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.
 
 	 	 	 	 	 	Average	 	Average	
 	 	 	 	Price	 	Benchmark	 	Realized	
Geographic Area	 	Product	 	Reference	 	Price	 	Price	
West Africa	 	 	 	 	 	 	 	 	
Ghana	 	Oil	 	Brent	 	$101.30/Bbl	 	$101.55/Bbl	
 
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
 
Costs
 
Operating costs for the properties in this report were furnished by Kosmos and are based on their operating expense reports. Such costs include only those costs directly applicable to the subject properties. The operating costs include a portion of general and administrative costs allocated directly to the contract area and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Kosmos. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the contract area or wells.
 
Development costs were furnished to us by Kosmos and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Kosmos were accepted without independent verification.
 
The proved undeveloped reserves in this report have been incorporated herein in accordance with Kosmos’ plans to develop these reserves as of December 31, 2014. The implementation of Kosmos’ development plans as presented to us and incorporated herein is subject to the approval process adopted by Kosmos’ management. As the result of our inquiries during the course of preparing this report, Kosmos has informed us that the development activities included herein have been subjected to and received the internal approvals required by Kosmos management at the appropriate
 
7

 
local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Kosmos. Additionally, Kosmos has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change or evolve from those under existing economic conditions as of December 31, 2014, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
 
Current costs used by Kosmos were held constant throughout the life of the properties.
 
Standards of Independence and Professional Qualification
 
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
 
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
 
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
 
We are independent petroleum engineers with respect to Kosmos Energy, LLC. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
 
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
 
Terms of Usage
 
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Kosmos.
 
8

 
Kosmos makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Kosmos has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and S-8 of Kosmos Energy, LLC of the references to our name as well as to the references to our third party report for Kosmos Energy, LLC, which appears in the December 31, 2014 annual report on Form 10-K of Kosmos Energy, LLC. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Kosmos Energy, LLC.
 
We have provided Kosmos with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Kosmos and the original signed report letter, the original signed report letter shall control and supersede the digital version.
 
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
 
 	 	Very truly yours,	 	
 	 	 	 	
 	 	RYDER SCOTT COMPANY, L.P.	 	
 	 	TBPE Firm Registration No. F-1580	 	

 	 	 	 	 	 	 	
 	 	/s/ Guale Ramirez, P.E.	 	 	 	 	 	
 	 	Guale Ramirez, P.E.
TBPE License No. 48318 Managing
Senior Vice President - International	 	 	 	 	 	
 	 	 	 	 	 	 	 	
 	 	/s/ Tosin Famurewa, P.E.	 	 	 	 	 	
 	 	Tosin Famurewa, P.E.	 	 	 	 	 	
 	 	TBPE License No. 100569	 	 	 	 	 	
 	 	Senior Vice President - International	 	 	 	 	 	
GR-TF (FWZ)/pl	 	 	 	 	 	 	 	

9

 
Professional Qualifications of Primary Technical Person
 
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Guadalupe Ramirez was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
 
Mr. Ramirez, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Managing Senior Vice President and also serves as a member of the Board of Directors. He is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Ramirez served in a number of engineering positions with Sun Oil Company and Natomas North America. For more information regarding Mr. Ramirez’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
 
Mr. Ramirez earned a Bachelor of Science Degree in Mechanical Engineering with honors from Texas A&M University in 1976 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.
 
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ramirez fulfills. As part of his 2014 continuing education hours, Mr. Ramirez attended an internally received 10 hours of formalized training as well as a day-long public forum, the 2013 RSC Reserves Conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Ramirez has also presented courses on the new SEC and SPE-PRMS reserves definitions on various occasions during 2011, 2012 and 2013 and received 40 hours of formalized external training during 2014, covering such topics as the Guidelines for Application of the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software, unconventional resources and ethics for consultants.
 
Based on his educational background, professional training and more than 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ramirez has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

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

 
Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
 
Reserves do not include quantities of petroleum being held in inventory.
 
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
 
RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
 
Reserves.                Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).
 
PROVED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
 
Proved oil and gas reserves.Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
(i)         The area of the reservoir considered as proved includes:
 
(A)         The area identified by drilling and limited by fluid contacts, if any, and
 
(B)         Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
2

 
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
 
(ii)     In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
(iv)   Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
 
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
 
(v)       Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
3

 
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
 
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
 
and
 
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
 
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
 
DEVELOPED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
 
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
(i)      Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
(ii)  Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Developed Producing (SPE-PRMS Definitions)
 
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
 
Developed Producing Reserves
 
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
 
Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 
Developed Non-Producing
 
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
 
Shut-In
 
Shut-in Reserves are expected to be recovered from:
 
(1)        completion intervals which are open at the time of the estimate, but which have not started producing;
(2)        wells which were shut-in for market conditions or pipeline connections; or
(3)        wells not capable of production for mechanical reasons.
 
Behind-Pipe
 
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.
 
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
 
UNDEVELOPED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
 
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
(i)               Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
(ii)           Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
(iii)       Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
2

Exhibit 99.2
 
 	 	HOUSTON, TEXAS 77002-5294	 	FAX (713) 651-0849
TELEPHONE (713) 651-9191	
 	 	 	 	 	
 	 	January 15, 2015	 	 	
 
Kosmos Energy, LLC
8176 Park Lane, Suite 500
Dallas, Texas 75231
 
Gentlemen:
 
At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain interests of Kosmos Energy, LLC (Kosmos) as of December 31, 2014. The subject properties are located in the country of Ghana offshore West Africa in the Deep Water Tano (DWT) block, hereafter referred to as “TEN Project Area”. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 15, 2015 and presented herein, was prepared for public disclosure by Kosmos in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
 
The properties evaluated by Ryder Scott in this report represent 36 percent of the total net proved liquid hydrocarbon reserves and 39 percent of the total net proved gas reserves of Kosmos as of December 31, 2014.
 
The estimated reserves and future net income amounts presented in this report, as of December 31, 2014, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to December 31, 2014, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.
 
SUITE 600, 1015 4TH STREET, S.W.	 	CALGARY, ALBERTA T2R 1J4	 	TEL (403) 262-2799	 	FAX (403) 262-2790	
621 17TH STREET, SUITE 1550	 	DENVER, COLORADO 80293-1501	 	TEL (303) 623-9147	 	FAX (303) 623-4258	

 
SEC PARAMETERS
Estimated Net Reserves and Income Data
Derived Through Certain Interest in the TEN Project Area
Kosmos Energy, LLC
As of December 31, 2014
 
 	 	Total	 	
 	 	Proved	 	
 	 	Undeveloped	 	
Net Remaining Reserves	 	 	 	
Oil/Condensate – MBarrels	 	26,274	 	
Fuel Gas – MMCF	 	5,512	 	
 	 	 	 	
Income Data (M$)	 	 	 	
Future Gross Revenue	 	$	2,661,586	 	
Deductions	 	1,498,909	 	
Future Net Income (FNI)	 	$	1,162,677	 	
 	 	 	 	
Discounted FNI @ 10% Before Taxes	 	$	594,487	 	
*Discounted FNI @ 10% After Taxes	 	$	451,174	 	
 
Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousands of barrels (MBarrels). All gas volumes are attributed to those volumes of gas that are consumed for fuel in field operations and are expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).
 
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PalantirCASH, a copyrighted product of Palantir Solutions. The program was used at the request of Kosmos. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
 
The deductions include the normal direct costs of operating the wells and facilities, development costs, certain abandonment costs net of salvage, and Additional Oil Entitlements (“AOE”). AOE is a contractual mechanism that prevents the contractor group from collecting “wind fall profits” and is treated herein as a deduction to the future gross revenue; however, for the TEN Project Area our economic analysis indicates no AOE deductions for the proved reserves. There are no production taxes associated with the TEN Project Area. The Discounted FNI @ 10% Before Taxes shown above does not include deductions for corporate income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. This FNI value was then adjusted by deducting corporate income taxes and the result is shown above as “Future Net Income @ 10% After Taxes.” The AOE calculation is determined at the block level and includes a rate of return calculation that is derived on an after corporate income tax basis based on interpretations of tax considerations made by Kosmos. All deductions pertaining to operating expenses, depletion, abandonment and royalties that were applied towards the calculation of corporate income taxes are strictly related to the TEN contract area. There are no corporate income tax deductions for the AOE calculation that are related to expenditures,
 
2

 
royalties, or any other deductible items outside of the TEN contract area. Liquid hydrocarbon reserves account for 100 percent of the total future gross revenue from proved reserves.
 
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded annually. These results are presented for your information and should not be construed as our estimate of fair market value.
 
Reserves Included in This Report
 
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
 
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.
 
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Kosmos’ request, this report addresses only the proved reserves attributable to the properties evaluated herein.
 
Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
 
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
 
The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce, or a revenue interest in such production. Furthermore, the subject properties located in Ghana may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Kosmos for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these
 
3

 
contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Kosmos the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Kosmos representations regarding such contractual information should be construed as a legal opinion on this matter.
 
Ryder Scott did not evaluate the country and geopolitical risks in the country of Ghana, where Kosmos operates or has interests. Kosmos operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.
 
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Kosmos owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
 
Estimates of Reserves
 
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.
 
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable
 
4

 
reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
 
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
 
The proved reserves for the properties included herein were estimated by the volumetric method and analogy. One hundred percent (100%) of the proved undeveloped reserves included herein were estimated by a combination of the volumetric method and analogy. These methods were used as a result of the field not being on production as of the date of this report and not having any production performance data to establish performance trends or to use as a basis for reserve estimates. The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were provided by Kosmos and were considered sufficient for the purpose thereof.
 
The offset Jubilee field was used as an analogy to the TEN Project Area for the purpose of estimating recovery factors. The Jubilee field has historically been operated under a pressure maintenance plan by means of water injection. The same type of pressure maintenance method is planned for the TEN Project Area.
 
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
 
Kosmos has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Kosmos with respect to property interests and contractual terms that govern future net income, production and well tests from examined wells, normal direct costs of operating the TEN Project Area and all the required facilities such as the FPSO, other costs such as transportation and/or processing fees, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Kosmos. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
 
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that
 
5

 
we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
 
Future Production Rates
 
There are no wells currently on production in the contract area. Our forecasts of future production rates are based on initial well test data and historical performance trends established by the wells in the offset and analogous Jubilee field, in which Kosmos also owns an interest. Future production rates were held constant, or adjusted for the effects of anticipated facility constraints, where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves.
 
As stated above, test data and other related information were used to estimate the anticipated initial production rates for the subject wells and locations which are not currently producing. Sales were estimated to commence at an anticipated date furnished by Kosmos. Wells or locations may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
 
The future production rates from the subject wells and locations may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.
 
Hydrocarbon Prices
 
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to December 31, 2014, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. All the proved volumes projected herein are forecast to be recovered prior to contract expiration.
 
Kosmos furnished us with the above mentioned average prices in effect on December 31, 2014. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are to be sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in this report.
 
The product prices that were actually used to determine the future gross revenue for the subject property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Kosmos. In the case of the TEN Project Area, Kosmos has estimated that the applicable differential is zero. The differential furnished to us was accepted as factual
 
6

 
data and reviewed by us for its reasonableness; however, we have not conducted an independent verification of the data used by Kosmos to determine this differential.
 
In addition, the table below summarizes the net volume weighted benchmark price adjusted for the differential and referred to herein as the “average realized price.” The average realized price shown in the table below was determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.
 
 	 	 	 	 	 	Average	 	Average	 	
 	 	 	 	Price	 	Benchmark	 	Realized	 	
Geographic Area	 	Product	 	Reference	 	Price	 	Price	 	
West Africa	 	 	 	 	 	 	 	 	 	
Ghana	 	Oil	 	Brent	 	$101.30/Bbl	 	$101.30/Bbl	 	
 
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
 
Costs
 
Operating costs for the properties in this report were furnished by Kosmos and are based on their analogy to the offset Jubilee field, which has been on production since November 2010 and in which Kosmos also owns an interest. Such costs include only those costs directly applicable to the subject properties. The operating costs include a portion of general and administrative costs allocated directly to the contract area and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Kosmos. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the contract area or wells.
 
Development costs were furnished to us by Kosmos and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Kosmos were accepted without independent verification.
 
The proved undeveloped reserves in this report have been incorporated herein in accordance with Kosmos’ plans to develop these reserves as of December 31, 2014. The implementation of Kosmos’ development plans as presented to us and incorporated herein is subject to the approval process adopted by Kosmos’ management. As the result of our inquiries during the course of preparing this report, Kosmos has informed us that the development activities included herein have been subjected to and received the internal approvals required by Kosmos management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Kosmos. Additionally, Kosmos has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change or evolve from those under
 
7

 
existing economic conditions as of December 31, 2014, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
 
Current costs used by Kosmos were held constant throughout the life of the properties.
 
Standards of Independence and Professional Qualification
 
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.
 
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
 
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
 
We are independent petroleum engineers with respect to Kosmos Energy, LLC. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
 
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.
 
Terms of Usage
 
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Kosmos.
 
Kosmos makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Kosmos has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and S-8 of Kosmos Energy, LLC of the references to our name as well as to the references to our third party report for Kosmos Energy, LLC, which appears in the December 31, 2014 annual report on Form 10-K of Kosmos Energy,
 
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LLC. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Kosmos Energy, LLC.
 
We have provided Kosmos with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Kosmos and the original signed report letter, the original signed report letter shall control and supersede the digital version.
 
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
 
 	 	Very truly yours,	 	
 	 	 	 	
 	 	RYDER SCOTT COMPANY, L.P.	 	
 	 	TBPE Firm Registration No. F-1580	 	 	

 	 	/s/ Guale Ramirez, P.E.	 	 	 	 	 	
 	 	Guale Ramirez, P.E.	 	 	 	 	 	 	
 	 	TBPE License No. 48318	 	 	 	 	 	 	 	
 	 	Managing Senior Vice President - International	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
 	 	/s/ Manuel Amaro	 	 	 	 	 	 	 	
 	 	Manuel Amaro	 	 	 	 	 	 	 	
 	 	Senior Petroleum Engineer	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
GR-MA (FWZ)/pl	 	 	 	 	 	 	 	 	 	
 
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Professional Qualifications of Primary Technical Person
 
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Guadalupe Ramirez was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
 
Mr. Ramirez, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Managing Senior Vice President and also serves as a member of the Board of Directors. He is responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Ramirez served in a number of engineering positions with Sun Oil Company and Natomas North America. For more information regarding Mr. Ramirez’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.
 
Mr. Ramirez earned a Bachelor of Science Degree in Mechanical Engineering with honors from Texas A&M University in 1976 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers.
 
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ramirez fulfills. As part of his 2014 continuing education hours, Mr. Ramirez attended an internally received 10 hours of formalized training as well as a day-long public forum, the 2013 RSC Reserves Conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Ramirez has also presented courses on the new SEC and SPE-PRMS reserves definitions on various occasions during 2011, 2012 and 2013 and received 40 hours of formalized external training during 2014, covering such topics as the Guidelines for Application of the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software, unconventional resources and ethics for consultants.
 
Based on his educational background, professional training and more than 35 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ramirez has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

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

 
Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
 
Reserves do not include quantities of petroleum being held in inventory.
 
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.
 
RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
 
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
 
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from undiscovered accumulations).
 
PROVED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
 
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
(i)     The area of the reservoir considered as proved includes:
 
(A)  The area identified by drilling and limited by fluid contacts, if any, and
 
(B)  Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
 
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PROVED RESERVES (SEC DEFINITIONS) CONTINUED
 
(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
(iii)  Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
(iv)   Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
 
(A)   Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
 
(B)   The project has been approved for development by all necessary parties and entities, including governmental entities.
 
(v)   Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
 
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
 
and
 
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
 
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).
 
DEVELOPED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
 
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
 
(i)   Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
(ii)  Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Developed Producing (SPE-PRMS Definitions)
 
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
 
Developed Producing Reserves
 
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
 
Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 
Developed Non-Producing
 
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
 
Shut-In
 
Shut-in Reserves are expected to be recovered from:
 
(1)        completion intervals which are open at the time of the estimate, but which have not started producing;
 
(2)   wells which were shut-in for market conditions or pipeline connections; or
 
(3)   wells not capable of production for mechanical reasons.
 
Behind-Pipe
 
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.
 
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
 
UNDEVELOPED RESERVES (SEC DEFINITIONS)
 
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
 
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
(i)      Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
(ii)    Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
(iii)   Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
 
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