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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 	 	
(Mark One)	 	
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
 
For the quarterly period ended March 31, 2017

☐	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	 	98-0686001	
(State or other jurisdiction of	 	(I.R.S. Employer	
incorporation or organization)	 	Identification No.)	
 
Clarendon House	 	 	
2 Church Street	 	 	
Hamilton, Bermuda	 	HM 11	
(Address of principal executive offices)	 	(Zip Code)	
 
Registrant’s telephone number, including area code: +1 441 295 5950
 
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☒  No ☐
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ☒  No ☐
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒	 	Accelerated filer ☐	
 	 	 	
Non-accelerated filer ☐	 	Smaller reporting company ☐	
(Do not check if a smaller reporting company)	 	 	
 	 	Emerging growth company ☐	
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ☐  No ☒
 
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	    	Outstanding at May 1, 2017	
Common Shares, $0.01 par value	 	387,693,693	

 

 
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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 3.

 	Page	
PART I. FINANCIAL INFORMATION	 	
 	 	
Glossary and Select Abbreviations 	3	
 	 	
Item 1. Financial Statements	 	
Consolidated Balance Sheets as of March 31, 2017 and December 31, 2016 	7	
Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016 	8	
Consolidated Statements of Shareholders’ Equity for the three months ended March 31, 2017 	9	
Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016 	10	
Notes to Consolidated Financial Statements 	11	
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 	26	
Item 3. Quantitative and Qualitative Disclosures about Market Risk 	37	
Item 4. Controls and Procedures 	39	
 	 	
PART II. OTHER INFORMATION	 	
 	 	
Item 1. Legal Proceedings 	40	
Item 1A. Risk Factors 	40	
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 	40	
Item 3. Defaults Upon Senior Securities 	40	
Item 4. Mine Safety Disclosures 	40	
Item 5. Other Information 	40	
Item 6. Exhibits 	41	
Signatures 	42	
Index to Exhibits 	43	
 
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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 (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.	
 	 	 	
“E&P”	 	Exploration and production.	
 	 	 	
“FASB”	 	Financial Accounting Standards Board.	
 	 	 	
“Farm-in”	 	An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and for taking on a portion of the drilling costs of one or more specific wells or other performance by the assignee as a condition of the assignment.	
 	 	 	
“Farm-out”	 	An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of the drilling costs of one or more specific wells and/or other work as a condition of the assignment.	
 	 	 	
“Field life cover ratio”	 	The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana assets, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.	
 	 	 	
“FPSO”	 	Floating production, storage and offloading vessel.	
 	 	 	
“Interest cover ratio”	 	The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.	
 	 	 	
“Loan life cover ratio”	 	The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.	
 	 	 	
“Make-whole redemption price”	 	The “make-whole redemption price” is equal to the outstanding principal amount of such notes plus the greater of 1) 1% of the then outstanding principal amount of such notes and 2) the present value of the notes at 103.9% and required interest payments thereon through August 1, 2017 at such redemption date.	
 	 	 	
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“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).	
 	 	 	
“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.	
 	 	 	
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“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 and potentially Mahogany, Teak and Akasa fields.	
 	 	 	
“Shelf margin”	 	The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.	
 	 	 	
“Stratigraphy”	 	The study of the composition, relative ages and distribution of layers of sedimentary rock.	
 	 	 	
“Stratigraphic trap”	 	A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.	
 	 	 	
“Structural trap”	 	A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and natural gas in the strata.	
 	 	 	
“Structural-stratigraphic trap”	 	A structural-stratigraphic trap is a combination trap with structural and stratigraphic features.	
 	 	 	
“Submarine fan”	 	A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.	
 	 	 	
“Three-way fault trap”	 	A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.	
 	 	 	
“Trap”	 	A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.	
 	 	 	
“Undeveloped acreage”	 	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.	
 
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KOSMOS ENERGY LTD.
 
CONSOLIDATED BALANCE SHEETS
 
(In thousands, except share data)

 	    	March 31,	    	December 31,	 	
 	 	2017	 	2016	 	
 	 	(Unaudited)	 	 	 	 	
Assets	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	153,194	 	$	194,057	 	
Restricted cash	 	 	65,835	 	 	24,506	 	
Receivables:	 	 	 	 	 	 	 	
Joint interest billings, net	 	 	87,324	 	 	63,249	 	
Oil sales	 	 	49,696	 	 	54,195	 	
Related party	 	 	21,977	 	 	 —	 	
Other	 	 	41,585	 	 	25,893	 	
Inventories	 	 	84,424	 	 	74,380	 	
Prepaid expenses and other	 	 	6,857	 	 	7,209	 	
Derivatives	 	 	34,899	 	 	31,698	 	
Total current assets	 	 	545,791	 	 	475,187	 	
 	 	 	 	 	 	 	 	
Property and equipment:	 	 	 	 	 	 	 	
Oil and gas properties, net	 	 	2,337,572	 	 	2,700,889	 	
Other property, net	 	 	7,261	 	 	8,003	 	
Property and equipment, net	 	 	2,344,833	 	 	2,708,892	 	
 	 	 	 	 	 	 	 	
Other assets:	 	 	 	 	 	 	 	
Equity method investment	 	 	133,893	 	 	 —	 	
Restricted cash	 	 	44,507	 	 	54,632	 	
Long-term receivables - joint interest billings	 	 	47,306	 	 	45,663	 	
Deferred financing costs, net of accumulated amortization of $11,898 and $11,213 at March 31, 2017 and December 31, 2016, respectively	 	 	4,563	 	 	5,248	 	
Long-term deferred tax assets	 	 	39,594	 	 	37,827	 	
Derivatives	 	 	8,031	 	 	3,808	 	
Other	 	 	14,531	 	 	10,208	 	
Total assets 	 	$	3,183,049	 	$	3,341,465	 	
 	 	 	 	 	 	 	 	
Liabilities and shareholders’ equity	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	
Accounts payable	 	$	217,722	 	$	220,627	 	
Accrued liabilities	 	 	118,114	 	 	129,706	 	
Derivatives	 	 	8,916	 	 	19,692	 	
Total current liabilities	 	 	344,752	 	 	370,025	 	
 	 	 	 	 	 	 	 	
Long-term liabilities:	 	 	 	 	 	 	 	
Long-term debt, net	 	 	1,174,677	 	 	1,321,874	 	
Derivatives	 	 	5,299	 	 	14,123	 	
Asset retirement obligations	 	 	65,223	 	 	63,574	 	
Deferred tax liabilities	 	 	506,122	 	 	482,221	 	
Other long-term liabilities	 	 	25,664	 	 	8,449	 	
Total long-term liabilities	 	 	1,776,985	 	 	1,890,241	 	
 	 	 	 	 	 	 	 	
Shareholders’ equity:	 	 	 	 	 	 	 	
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at March 31, 2017 and December 31, 2016	 	 	 —	 	 	 —	 	
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 396,816,463 and 395,859,061 issued at March 31, 2017 and December 31, 2016, respectively	 	 	3,968	 	 	3,959	 	
Additional paid-in capital	 	 	1,984,710	 	 	1,975,247	 	
Accumulated deficit	 	 	(879,251)	 	 	(850,410)	 	
Treasury stock, at cost, 9,175,328 and 9,101,395 shares at March 31, 2017 and December 31, 2016, respectively	 	 	(48,115)	 	 	(47,597)	 	
Total shareholders’ equity	 	 	1,061,312	 	 	1,081,199	 	
Total liabilities and shareholders’ equity 	 	$	3,183,049	 	$	3,341,465	 	
 
See accompanying notes.
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KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
(In thousands, except per share data)
 
(Unaudited)

 	 	Three Months Ended	 	 	
 	 	March 31,	 	 	
 	    	2017	    	2016	    	 	
Revenues and other income:	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	103,432	 	$	62,125	 	 	
Other income, net	 	 	48,534	 	 	 8	 	 	
 	 	 	 	 	 	 	 	 	
Total revenues and other income	 	 	151,966	 	 	62,133	 	 	
 	 	 	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	19,886	 	 	29,392	 	 	
Facilities insurance modifications, net	 	 	2,574	 	 	 —	 	 	
Exploration expenses	 	 	105,714	 	 	23,858	 	 	
General and administrative	 	 	15,787	 	 	17,920	 	 	
Depletion and depreciation	 	 	34,978	 	 	31,266	 	 	
Interest and other financing costs, net	 	 	16,786	 	 	10,324	 	 	
Derivatives, net	 	 	(37,857)	 	 	(4,345)	 	 	
Other expenses, net	 	 	762	 	 	14,733	 	 	
 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	158,630	 	 	123,148	 	 	
 	 	 	 	 	 	 	 	 	
Loss before income taxes	 	 	(6,664)	 	 	(61,015)	 	 	
Income tax expense (benefit)	 	 	22,177	 	 	(2,022)	 	 	
 	 	 	 	 	 	 	 	 	
Net loss	 	$	(28,841)	 	$	(58,993)	 	 	
 	 	 	 	 	 	 	 	 	
Net loss per share:	 	 	 	 	 	 	 	 	
Basic	 	$	(0.07)	 	$	(0.15)	 	 	
Diluted  	 	$	(0.07)	 	$	(0.15)	 	 	
 	 	 	 	 	 	 	 	 	
Weighted average number of shares used to compute net loss per share:	 	 	 	 	 	 	 	 	
Basic	 	 	387,312	 	 	384,435	 	 	
Diluted  	 	 	387,312	 	 	384,435	 	 	
 
See accompanying notes.
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KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
 
(In thousands)
 
(Unaudited)

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	Additional	 	 	 	 	 	 	 	 	 	 	
 	 	Common Shares	 	Paid-in	 	Accumulated	 	Treasury	 	 	 	 	
 	    	Shares	    	 Amount 	    	Capital	    	Deficit	    	Stock	    	Total	 	
Balance as of December 31, 2016	 	395,859	 	$	3,959	 	$	1,975,247	 	$	(850,410)	 	$	(47,597)	 	$	1,081,199	 	
Equity-based compensation	 	 —	 	 	 —	 	 	10,069	 	 	 —	 	 	 —	 	 	10,069	 	
Restricted stock awards and units	 	957	 	 	 9	 	 	(9)	 	 	 —	 	 	 —	 	 	 —	 	
Purchase of treasury stock	 	 —	 	 	 —	 	 	(597)	 	 	 —	 	 	(518)	 	 	(1,115)	 	
Net loss	 	 —	 	 	 —	 	 	 —	 	 	(28,841)	 	 	 —	 	 	(28,841)	 	
Balance as of March 31, 2017	 	396,816	 	$	3,968	 	$	1,984,710	 	$	(879,251)	 	$	(48,115)	 	$	1,061,312	 	
 
See accompanying notes.
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KOSMOS ENERGY LTD.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
(In thousands)
 
(Unaudited)

 	 	Three Months Ended March 31,	 	
 	    	2017	    	2016	 	
Operating activities	 	 	 	 	 	 	 	
Net loss	 	$	(28,841)	 	$	(58,993)	 	
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:	 	 	 	 	 	 	 	
Depletion, depreciation and amortization	 	 	37,529	 	 	33,817	 	
Deferred income taxes	 	 	22,133	 	 	(1,951)	 	
Unsuccessful well costs	 	 	88	 	 	2,222	 	
Change in fair value of derivatives	 	 	(38,177)	 	 	(2,377)	 	
Cash settlements on derivatives, net (including $11.4 million and $56.6 million on commodity hedges during 2017 and 2016	 	 	11,153	 	 	56,901	 	
Equity-based compensation	 	 	9,830	 	 	10,635	 	
Other	 	 	621	 	 	14,969	 	
Changes in assets and liabilities:	 	 	 	 	 	 	 	
(Increase) decrease in receivables	 	 	(44,853)	 	 	39,894	 	
(Increase) decrease in inventories	 	 	(10,044)	 	 	2,237	 	
Decrease in prepaid expenses and other	 	 	352	 	 	13,674	 	
Decrease in accounts payable	 	 	(2,905)	 	 	(58,501)	 	
Increase (decrease) in accrued liabilities	 	 	12,732	 	 	(36,910)	 	
Net cash provided by (used in) operating activities	 	 	(30,382)	 	 	15,617	 	
 	 	 	 	 	 	 	 	
Investing activities	 	 	 	 	 	 	 	
Oil and gas assets	 	 	(31,810)	 	 	(226,571)	 	
Other property	 	 	(271)	 	 	(47)	 	
Proceeds on sale of assets	 	 	203,919	 	 	 —	 	
Net cash provided by (used in) investing activities	 	 	171,838	 	 	(226,618)	 	
 	 	 	 	 	 	 	 	
Financing activities	 	 	 	 	 	 	 	
Borrowings under long-term debt	 	 	 —	 	 	150,000	 	
Payments on long-term debt	 	 	(150,000)	 	 	 —	 	
Purchase of treasury stock	 	 	(1,115)	 	 	(1,074)	 	
Net cash provided by (used in) financing activities	 	 	(151,115)	 	 	148,926	 	
 	 	 	 	 	 	 	 	
Net decrease in cash, cash equivalents and restricted cash	 	 	(9,659)	 	 	(62,075)	 	
Cash, cash equivalents and restricted cash at beginning of period	 	 	273,195	 	 	310,862	 	
Cash, cash equivalents and restricted cash at end of period	 	$	263,536	 	$	248,787	 	
 	 	 	 	 	 	 	 	
Supplemental cash flow information	 	 	 	 	 	 	 	
Cash paid for:	 	 	 	 	 	 	 	
Interest	 	$	20,559	 	$	14,611	 	
Income taxes	 	$	 —	 	$	2,734	 	
 	 	 	 	 	 	 	 	
Non-cash activity:	 	 	 	 	 	 	 	
Conversion of joint interest billings receivable to long-term note receivable	 	$	4,042	 	$	3,417	 	
Contribution to equity method investment	 	$	133,894	 	$	 —	 	
 
See accompanying notes.
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KOSMOS ENERGY LTD.
 
Notes to Consolidated Financial Statements
(Unaudited)
 
1. Organization
 
Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise.
 
Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and is traded under the ticker symbol KOS.
 
We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are currently related to production located offshore Ghana.
 
2. Accounting Policies
 
General
 
The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of March 31, 2017, the changes in the consolidated statements of shareholders’ equity for the three months ended March 31, 2017, the consolidated results of operations for the three months ended March 31, 2017 and 2016, and the consolidated cash flows for the three months ended March 31, 2017 and 2016. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2016, included in our annual report on Form 10-K.
 
Investment in Corporate Joint Venture
 
Kosmos holds a 50.01% interest in Kosmos BP Senegal Limited (“KBSL”), which we exercise significant influence over. Our investment in KBSL is accounted for under the equity method of accounting. In applying the equity method of accounting, our investment in KBSL was initially recorded at carryover basis. As of March 31, 2017, our investment in KBSL was $133.9 million and is reported as an equity method investment in our consolidated balance sheets. We had related party receivables of $22.0 million as of March 31, 2017, which relate to amounts due from KBSL for costs incurred by Kosmos on behalf of KBSL.
 
Reclassifications
 
Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows. 
 
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Cash, Cash Equivalents and Restricted Cash

 	 	March 31,	 	December 31,	 	
 	 	2017	 	2016	 	
 	 	(In thousands)	 	
Cash and cash equivalents	 	$	153,194	 	$	194,057	 	
Restricted cash - current	 	 	65,835	 	 	24,506	 	
Restricted cash - long-term	 	 	44,507	 	 	54,632	 	
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	 	$	263,536	 	$	273,195	 	

Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
 
In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of March 31, 2017 and December 31, 2016, we had $24.5 million in current restricted cash to meet this requirement.
 
In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of March 31, 2017 and December 31, 2016, we had $41.3 million and zero, respectively, of current restricted cash and $44.5 million and $54.6 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts.
 
Inventories
 
Inventories consisted of $71.3 million and $68.1 million of materials and supplies and $13.1 million and $6.3 million of hydrocarbons as of March 31, 2017 and December 31, 2016, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded a write down of zero and $15.7 million during the three months ended March 31, 2017 and 2016, respectively, for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows.
 
Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

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3. Acquisitions and Divestitures
 
In December 2016, we announced transactions with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. The Mauritania and Senegal transactions closed in January 2017 and February 2017, respectively. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in Kosmos BP Senegal Limited (“KBSL”), our majority owned affiliate company which holds a 60% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million. However, we have conditionally agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis Corporation by which BP will acquire Timis Corporation’s entire 30% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal, subject to government approval. Thereafter, KBSL’s participating interest in these blocks will remain at 60%. However, in the event the transaction between BP and Timis Corporation does not close, then the call option exercise remains valid. In consideration for these transactions, Kosmos received $162 million in cash up front during the first quarter of 2017 and will receive a $221 million exploration and appraisal carry, up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discovery and prevailing oil prices. The effective date of these transactions was July 1, 2016, with BP paying interim costs from the effective date to the closing dates. We reduced our unproved property balance by $221.9 million for the consideration received as a result of these transactions including the upfront cash and interim costs from the transaction date to the effective date.

4. Joint Interest Billings
 
The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.
 
In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues under the terms of the Deepwater Tano (“DT”) petroleum contract. As of March 31, 2017 and December 31, 2016, the joint interest billing receivables due from GNPC for the TEN development costs were $45.7 million and $44.0 million, respectively, which are 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:

 	    	March 31,	    	December 31,	 	
 	 	2017	 	2016	 	
 	 	(In thousands)	 	
Oil and gas properties:	 	 	 	 	 	 	 	
Proved properties	 	$	1,375,364	 	$	1,385,331	 	
Unproved properties	 	 	592,275	 	 	919,056	 	
Support equipment and facilities	 	 	1,392,365	 	 	1,386,448	 	
Total oil and gas properties	 	 	3,360,004	 	 	3,690,835	 	
Accumulated depletion	 	 	(1,022,432)	 	 	(989,946)	 	
Oil and gas properties, net	 	 	2,337,572	 	 	2,700,889	 	
 	 	 	 	 	 	 	 	
Other property	 	 	37,287	 	 	37,186	 	
Accumulated depreciation	 	 	(30,026)	 	 	(29,183)	 	
Other property, net	 	 	7,261	 	 	8,003	 	
 	 	 	 	 	 	 	 	
Property and equipment, net	 	$	2,344,833	 	$	2,708,892	 	
 
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We recorded depletion expense of $32.5 million and $29.2 million for the three months ended March 31, 2017 and 2016, respectively.
 
6. Suspended Well Costs
 
The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the three months ended March 31, 2017. The table excludes $0.1 million in costs that were capitalized and subsequently expensed during the same period.

 	 	March 31,	 	
 	    	2017	 	
 	 	(In thousands)	 	
Beginning balance 	 	$	734,463	 	
Additions to capitalized exploratory well costs pending the determination of proved reserves 	 	 	476	 	
Reclassification due to determination of proved reserves 	 	 	 —	 	
Divestitures(1)	 	 	(206,400)	 	
Contribution of oil and gas property to equity method investment	 	 	(131,764)	 	
Capitalized exploratory well costs charged to expense 	 	 	 —	 	
Ending balance 	 	$	396,775	 	

 	(1)	 	Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal tranasactions with BP.	
 
The following table provides an 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:

 	    	March 31, 2017	    	December 31, 2016	 	
 	 	(In thousands, except well counts)	 	
Exploratory well costs capitalized for a period of one year or less	 	$	3,717	 	$	279,809	 	
Exploratory well costs capitalized for a period of one to two years	 	 	179,397	 	 	244,804	 	
Exploratory well costs capitalized for a period of three to eight years	 	 	213,661	 	 	209,850	 	
Ending balance	 	$	396,775	 	$	734,463	 	
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	 	 	 5	 	 	 5	 	
 
As of March 31, 2017, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Mahogany, Teak (formerly Teak-1 and Teak-2) and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border and the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania.
 
Mahogany and Teak Discoveries — In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure. The expansion of the Jubilee Unit becomes effective upon approval by Ghana’s Ministry of Petroleum of the Greater Jubilee Full Field Development Plan (“GJFFDP”), which was submitted to the government of Ghana in December 2015. The GJFFDP encompasses future development of the Jubilee Field, in addition to future development of the Mahogany and Teak discoveries, which were declared commercial during 2015. We are currently in discussions with the government of Ghana concerning the GJFFDP. Upon approval of the GJFFDP by the Ministry of Energy, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy.
 
Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. The
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WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block, including the Akasa Discovery, to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy.
 
Wawa Discovery — In February 2016, we requested the Ghana Ministry of Energy to approve the enlargement of the areal extent of the TEN fields and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along with the requirement to integrate the Wawa Discovery into the TEN PoD. We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation.
 
Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-1 in Mauritania and Guembeul-1 in Senegal. Following additional evaluation, a decision regarding commerciality will be made.
 
BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made.
7. Debt

 	 	March 31,	 	December 31,	 	
 	   	2017	   	2016	 	
 	 	(In thousands)	 	
Outstanding debt principal balances:	 	 	 	 	 	 	 	
Facility	 	$	700,000	 	$	850,000	 	
Senior Notes	 	 	525,000	 	 	525,000	 	
Total	 	 	1,225,000	 	 	1,375,000	 	
Unamortized deferred financing costs and discounts(1)	 	 	(50,323)	 	 	(53,126)	 	
Long-term debt, net 	 	$	1,174,677	 	$	1,321,874	 	

 	(1)	 	Includes $28.5 million and $30.3 million of unamortized deferred financing costs related to the Facility and $21.8 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of March 31, 2017 and December 31, 2016, respectively.	
 
Facility
 
In March 2014, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.
 
In March 2017, following the lender’s semi-annual redetermination, the borrowing base under our Facility was $1.3 billion (effective April 1, 2017). The borrowing base calculation includes value related to the Jubilee and TEN fields. As of March 31, 2017, borrowings under the Facility totaled $700.0 million and the undrawn availability under the Facility was $766.9 million (as of April 1, 2017, the availability is $600.8 million).
 
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 facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of March 31, 2017, we had no letters of credit issued under the Facility.
 
We were in compliance with the financial covenants contained in the Facility as of March 31, 2017 (the most recent assessment date). The Facility contains customary cross default provisions.
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Corporate Revolver
 
In June 2015, we amended and restated the Corporate Revolver from a number of financial institutions, increasing the borrowing capacity to $400.0 million, extending the maturity date to November 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of March 31, 2017, we have $4.6 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over the remaining term. These deferred financing costs are included in the Other assets section of the consolidated balance sheet.
 
As of March 31, 2017, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million. We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2017 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
 
Revolving Letter of Credit Facility
 
In July 2016, we amended and restated the revolving letter of credit facility agreement (“LC Facility”), extending the maturity date to July 2019. As of March 31, 2017, the LC Facility size was $115.0 million with additional commitments of up to $10.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments include increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. As of March 31, 2017, there were 11 outstanding letters of credit totaling $112.8 million under the LC Facility. The LC Facility contains customary cross default provisions. In April 2017, we reduced the size of our LC Facility to $70 million.
 
7.875% Senior Secured Notes due 2021
 
During August 2014, the Company issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
 
During April 2015, we issued an additional $225.0 million of Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
 
The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries.
 
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At March 31, 2017, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

 	 	Payments Due by Year	 	
 	    	Total	   	2017(2)	  	2018	 	2019	   	2020	 	2021	   	Thereafter	 	
 	 	(In thousands)	 	
Principal debt repayments(1)	 	$	1,225,000	 	$	 —	 	$	 —	 	$	100,377	 	$	404,971	 	$	719,652	 	$	 —	 	

 	(1)	 	Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of March 31, 2017, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. 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 March 31, 2017, there were no borrowings under the Corporate Revolver.	

 	(2)	 	Represents payments for the period April 1, 2017 through December 31, 2017.	
 
Interest and other financing costs, net
 
Interest and other financing costs, net incurred during the periods is comprised of the following:

 	Three Months Ended March 31,	 	
 	2017	    	2016	 	
 	(In thousands)	 	
Interest expense	$	23,181	 	$	20,948	 	
Amortization—deferred financing costs	 	2,551	 	 	2,551	 	
Capitalized interest	 	(9,559)	 	 	(16,446)	 	
Deferred interest	 	315	 	 	(407)	 	
Interest income	 	(980)	 	 	(368)	 	
Other, net	 	1,278	 	 	4,046	 	
Interest and other financing costs, net	$	16,786	 	$	10,324	 	

8. Derivative Financial Instruments
 
We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.
 
We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures.
 
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Oil Derivative Contracts
 
The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of March 31, 2017. Volumes are net of any offsetting derivative contracts entered into.

 	 	 	 	 	 	Weighted Average Dated Brent Price per Bbl	 	
 	 	 	 	 	 	Net Deferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Premium	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Term	    	Type of Contract	    	MBbl	    	Payable, Net	    	Swap	    	Sold Put	    	Floor	    	Ceiling	    	Call	 	
2017:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
April — December	 	Swap with puts/calls	 	1,505	 	$	2.13	 	$	72.50	 	$	55.00	 	$	 —	 	$	 —	 	$	90.00	 	
April — December	 	Swap with puts	 	1,505	 	 	 —	 	 	64.95	 	 	50.00	 	 	 —	 	 	 —	 	 	 —	 	
April — December	 	Three-way collars	 	2,012	 	 	2.57	 	 	 —	 	 	30.00	 	 	45.00	 	 	57.50	 	 	 —	 	
April — December	 	Sold calls(1)	 	1,500	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	85.00	 	 	 —	 	
2018:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Three-way collars	 	2,913	 	$	0.74	 	$	 —	 	$	41.57	 	$	56.57	 	$	65.90	 	$	 —	 	
January — December	 	Four-way collars	 	2,000	 	 	0.93	 	 	 —	 	 	40.00	 	 	50.00	 	 	61.00	 	 	70.00	 	
January — December	 	Sold calls(1)	 	2,000	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	65.00	 	 	 —	 	
2019:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Sold calls(1)	 	913	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	80.00	 	$	 —	 	

 	(1)	 	Represents call option contracts sold to counterparties to enhance other derivative positions.	
 
In April 2017, we entered into three-way collar contracts for 1.0 MMBbl from January 2018 through December 2018 with a floor price of $50.00 per barrel, and a ceiling price of $62.00 per barrel and a purchased call price of $70.00 per barrel. The contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of $2.15 per barrel.
 
In May 2017, we sold 1.0 MMBbl of put contracts from January 2018 through December 2018 with a strike price of $40.00 per barrel. We used part of the proceeds to increase the ceiling for 1.0 MMBbl of sold calls in the second half of 2017 from $55.00 to $60.00. These contracts are indexed to Dated Brent prices.
 
Interest Rate Derivative Contracts
 
The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of March 31, 2017:

 	 	 	 	 	 	Weighted Average	 	 	
Term	    	Type of Contract	 	Floating Rate	    	Notional	    	Swap	    	Sold Call	 	 	
 	 	 	 	 	 	(In thousands)	 	 	 	 	 	 	
April 2017 — December 2018	 	Capped swap	 	1-month LIBOR	 	$	200,000	 	1.23	%  	3.00	%	 	
 
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The following tables disclose the Company’s derivative instruments as of March 31, 2017 and December 31, 2016 and gain/(loss) from derivatives during the three months ended March 31, 2017 and 2016, respectively:

 	 	 	 	Estimated Fair Value	 	
 	 	 	 	Asset (Liability)	 	
 	    	    	    	March 31,	    	December 31,	    	
Type of Contract 	    	Balance Sheet Location	    	2017	    	2016	    	
 	 	 	 	(In thousands)	 	
Derivatives not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	
Derivative assets:	 	 	 	 	 	 	 	 	 	
Commodity(1)	 	Derivatives assets—current	 	$	34,899	 	$	31,698	 	
Commodity(2)	 	Derivatives assets—long-term	 	 	7,390	 	 	3,226	 	
Interest rate	 	Derivatives assets—long-term	 	 	641	 	 	582	 	
Derivative liabilities:	 	 	 	 	 	 	 	 	 	
Commodity(3)	 	Derivatives liabilities—current	 	 	(8,883)	 	 	(19,163)	 	
Interest rate	 	Derivatives liabilities—current	 	 	(33)	 	 	(529)	 	
Commodity(4)	 	Derivatives liabilities—long-term	 	 	(5,299)	 	 	(14,123)	 	
Total derivatives not designated as hedging instruments	 	 	 	$	28,715	 	$	1,691	 	

 	(1)	 	Includes net deferred premiums payable of $3.5 million and $3.9 million related to commodity derivative contracts as of March 31, 2017 and December 31, 2016, respectively.	

 	(2)	 	Includes net deferred premiums payable of $3.7 million and $2.5 million related to commodity derivative contracts as of March 31, 2017 and December 31, 2016, respectively.	

 	(3)	 	Includes zero and $30.9 thousand as of March 31, 2017 and December 31, 2016, respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $5.5 million and $6.2 million related to commodity derivative contracts as of March 31, 2017 and December 31, 2016, respectively.	

 	(4)	 	Includes net deferred premiums receivable of $0.4 million and net deferred premiums payable of $0.6 million related to commodity derivative contracts as of March 31, 2017 and December 31, 2016, respectively.	

 	 	 	 	Amount of Gain/(Loss)	 	
 	 	 	 	Three Months Ended	 	
 	 	 	 	March 31,	 	
Type of Contract	    	Location of Gain/(Loss)	    	2017	    	2016	 	
 	 	 	 	(In thousands)	 	
Derivatives not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	
Commodity(1)	 	Oil and gas revenue	 	$	(8)	 	$	610	 	
Commodity	 	Derivatives, net	 	 	37,857	 	 	4,345	 	
Interest rate	 	Interest expense	 	 	328	 	 	(2,578)	 	
Total derivatives not designated as hedging instruments	 	 	 	$	38,177	 	$	2,377	 	

 	(1)	 	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 March 31, 2017 and December 31, 2016, 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.
 
9. Fair Value Measurements
 
In accordance with ASC Topic 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
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reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:
 
 	·	 	Level 1 — quoted prices for identical assets or liabilities in active markets.	
 
 	·	 	Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.	
 
 	·	 	Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.	
 
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2017 and December 31, 2016, for each fair value hierarchy level:

 	    	Fair Value Measurements Using:	 	
 	 	Quoted Prices in	 	 	 	 	 	 	 	 	
 	 	Active Markets for	 	Significant Other	 	Significant	 	 	 	 	
 	 	Identical Assets	 	Observable Inputs	 	Unobservable Inputs	 	 	 	 	
 	    	(Level 1)	    	(Level 2)	    	(Level 3)	    	Total	 	
 	 	(In thousands)	 	
March 31, 2017	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	 —	 	$	42,289	 	$	 —	 	$	42,289	 	
Interest rate derivatives	 	 	 —	 	 	641	 	 	 —	 	 	641	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	 	 —	 	 	(14,182)	 	 	 —	 	 	(14,182)	 	
Interest rate derivatives	 	 	 —	 	 	(33)	 	 	 —	 	 	(33)	 	
Total	 	$	 —	 	$	28,715	 	$	 —	 	$	28,715	 	
December 31, 2016	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	$	 —	 	$	34,924	 	$	 —	 	$	34,924	 	
Interest rate derivatives	 	 	 —	 	 	582	 	 	 —	 	 	582	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivatives	 	 	 —	 	 	(33,286)	 	 	 —	 	 	(33,286)	 	
Interest rate derivatives	 	 	 —	 	 	(529)	 	 	 —	 	 	(529)	 	
Total	 	$	 —	 	$	1,691	 	$	 —	 	$	1,691	 	
 
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
 
Commodity Derivatives
 
Our commodity derivatives represent crude oil four-way collars, three-way collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 8 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.
 
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Provisional Oil Sales
 
The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date.
 
Interest Rate Derivatives
 
We enter into interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. We also enter into capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap, and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.
 
Debt
 
The following table presents the carrying values and fair values at March 31, 2017 and December 31, 2016:

 	 	March 31, 2017	 	December 31, 2016	 	
 	    	Carrying Value	    	Fair Value	    	Carrying Value	    	Fair Value	 	
 	 	(In thousands)	 	
Senior Notes	 	$	504,653	 	$	529,594	 	$	503,716	 	$	528,938	 	
Facility	 	 	700,000	 	 	700,000	 	 	850,000	 	 	850,000	 	
Total	 	$	1,204,653	 	$	1,229,594	 	$	1,353,716	 	$	1,378,938	 	
 
The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.
 
10. Equity-based Compensation
 
Restricted Stock Awards and Restricted Stock Units
 
We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.8 million and $10.6 million during the three months ended March 31, 2017 and 2016, respectively. The total tax benefit for the three months ended March 31, 2017 and 2016 was $3.3 million and $3.6 million, respectively. Additionally, we recorded a tax windfall and shortfall related to equity-based compensation of $0.5 million and $1.2 million for the three months ended March 31, 2017 and 2016, respectively. The fair value of awards vested during the three months ended March 31, 2017 and 2016 was approximately $8.8 million and $4.6 million, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.
 
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The following table reflects the outstanding restricted stock awards as of March 31, 2017:

 	 	 	 	Weighted-	 	
 	 	Service Vesting	 	Average	 	
 	 	Restricted Stock	 	Grant-Date	 	
 	    	Awards	    	Fair Value	    	
 	 	(In thousands)	 	 	 	 	
Outstanding at December 31, 2016	 	488	 	$	8.83	 	
Granted	 	 —	 	 	 —	 	
Forfeited	 	 —	 	 	 —	 	
Vested	 	(220)	 	 	8.62	 	
Outstanding at March 31, 2017	 	268	 	 	9.00	 	
 
The following table reflects the outstanding restricted stock units as of March 31, 2017:

 	 	 	 	Weighted-	 	Market / Service	 	Weighted-	 	
 	 	Service Vesting	 	Average	 	Vesting	 	Average	 	
 	 	Restricted Stock	 	Grant-Date	 	Restricted Stock	 	Grant-Date	 	
 	 	Units	  	Fair Value	 	Units	 	Fair Value	 	
 	 	(In thousands)	 	 	 	 	(In thousands)	 	 	 	 	
Outstanding at December 31, 2016	 	4,160	 	$	6.91	 	7,194	 	$	12.29	 	
Granted	 	1,867	 	 	6.39	 	2,146	 	 	9.50	 	
Forfeited	 	(33)	 	 	8.01	 	(11)	 	 	11.82	 	
Vested	 	(971)	 	 	5.72	 	(61)	 	 	15.44	 	
Outstanding at March 31, 2017	 	5,023	 	 	6.94	 	9,268	 	 	11.63	 	
 
As of March 31, 2017, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $53.4 million over a weighted average period of 1.71 years. At March 31, 2017, the Company had approximately 2.4 million shares that remain available for issuance under the LTIP.
 
For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value was $9.45 per award for restricted stock awards and ranged from $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and was 55.0% for the restricted stock awards and ranged from 44.0% to 54.0% for restricted stock units. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and was 0.5% for restricted stock awards and ranged from 0.5% to 1.4% for restricted stock units.

11. Income Taxes
 
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax exempt jurisdictions from our evaluation of the estimated annual effective income tax rate.
 
Income tax expense (benefit) was $22.2 million and $(2.0) million for the three months ended March 31, 2017 and 2016, respectively. The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.
 
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Income (loss) before income taxes is composed of the following:

 	 	Three Months Ended March 31,	 	
 	    	2017	    	2016	 	
 	 	(In thousands)	 	
Bermuda	 	$	(16,181)	 	$	(15,797)	 	
United States	 	 	1,412	 	 	2,096	 	
Foreign—other	 	 	8,105	 	 	(47,314)	 	
Income (loss) before income taxes	 	$	(6,664)	 	$	(61,015)	 	
 
Our effective tax rate for the three months ended March 31, 2017 and 2016 is 333% and 3%, respectively. The effective tax rate for the United States is approximately 21% and 108% for the three months ended March 31, 2017 and 2016, respectively. The effective tax rate in the United States is impacted by the effect of equity-based compensation tax shortfalls and windfalls equal to the difference between the income tax benefit recognized for financial statement purposes and the income tax benefit realized for tax return purposes. The effective tax rate for Ghana is approximately 35% for the three months ended March 31, 2017 and 2016. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing, which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax.
 
A subsidiary of the Company files a U.S. federal income tax return and a Texas margin tax return. In addition to the United States, the Company files income tax returns in the countries in which we operate. The Company is open to U.S. federal income tax examinations for tax years 2013 through 2016 and to Texas margin tax examinations for the tax years 2011 through 2016. In addition, the Company is open to income tax examinations for years 2011 through 2016 in its significant other foreign jurisdictions, primarily Ghana.
 
As of March 31, 2017, 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.
 
12. Net Income (Loss) Per Share
 
The following table is a reconciliation between net income and the amounts used to compute basic and diluted net income per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share:

 	 	Three Months Ended	
 	 	March 31,	
 	   	2017	 	2016	 	
 	 	(In thousands, except per share data)	
Numerator:	 	 	 	 	 	 	 	
Net loss	 	$	(28,841)	 	$	(58,993)	 	
Basic income allocable to participating securities(1)	 	 	 —	 	 	 —	 	
Basic net loss allocable to common shareholders	 	 	(28,841)	 	 	(58,993)	 	
Diluted adjustments to income allocable to participating securities(1)	 	 	 —	 	 	 —	 	
Diluted net loss allocable to common shareholders	 	$	(28,841)	 	$	(58,993)	 	
Denominator:	 	 	 	 	 	 	 	
Weighted average number of shares outstanding:	 	 	 	 	 	 	 	
Basic	 	 	387,312	 	 	384,435	 	
Restricted stock awards and units(1)(2)	 	 	 —	 	 	 —	 	
Diluted	 	 	387,312	 	 	384,435	 	
Net loss per share:	 	 	 	 	 	 	 	
Basic	 	$	(0.07)	 	$	(0.15)	 	
Diluted	 	$	(0.07)	 	$	(0.15)	 	

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

 	(2)	 	We excluded outstanding restricted stock awards and units of 14.6 million and 13.6 million for the three months ended March 31, 2017 and 2016, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.	
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13. Commitments and Contingencies
 
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.
 
We currently have a commitment to drill two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to their maximum $221 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Sao Tome and Principe, Morocco and Western Sahara, we have 3D seismic requirements of 4,750 square kilometers, 3,000 square kilometers and 5,000 square kilometers, respectively. Additionally, in Morocco certain geological studies are also required.
 
In January 2017, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., elected to cancel the fourth year option of the Atwood Achiever drilling rig contract and revert to the original day rate of approximately $0.6 million per day and original agreement end date in November 2017. During the first quarter of 2017, KEV made a rate recovery payment of $48.1 million representing the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the election was exercised plus certain administrative costs.
 
In November 2015, we entered into a line of credit agreement with Timis Corporation, whereby Timis Corporation may draw up to $30.0 million on the line of credit to offset its joint interest billings arising from costs under the Senegal petroleum agreements. Interest accrues on drawn balances at 7.875%. As of March 31, 2017, there was $14.5 million outstanding under the agreement, which is included in other long-term assets. In addition to the amount outstanding under the agreement, as of March 31, 2017 Timis Corporation has a $1.6 million joint interest billing receivable that will be applied against the line of credit if not paid by the due date. We have conditionally agreed with Timis Corporation to terminate this line of credit agreement in the event Timis Corporation’s transaction with BP for the transfer of Timis Corporation’s 30% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal is completed. In such event Timis Corporation will pay $16.0 million to Kosmos on the earlier of the following: (i) an additional hydrocarbon discovery is made in either of these two blocks and the coventurers then elect to submit an appraisal plan; (ii) December 31, 2018; or (iii) the date that a final investment decision is made for developing the Greater Tortue field. In the event that Timis Corporation’s transaction with BP does not close, then the line of credit agreement shall continue as before.
 
Future minimum rental commitments under our leases at March 31, 2017, are as follows:

 	 	Payments Due By Year(1)	 	
 	 	Total	 	2017(2)	 	2018	 	2019	 	2020	 	2021	 	Thereafter	 	
 	 	(In thousands)	 	
Operating leases(3)	 	$	12,568	 	$	3,963	 	$	4,600	 	$	3,940	 	$	65	 	$	 —	 	$	 —	 	
Atwood Achiever drilling rig contract	 	 	133,875	 	 	133,875	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	

 	(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)	 	Represents payments for the period from April 1, 2017 through December 31, 2017.	
 
 	(3)	 	Primarily relates to corporate office and foreign office leases.	

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14. Additional Financial Information
 
Accrued Liabilities
 
Accrued liabilities consisted of the following:

 	    	March 31,	    	December 31,	 	
 	   	2017	   	2016	 	
 	 	(In thousands)	 	
Accrued liabilities:	 	 	 	 	 	 	 	
Exploration, development and production	 	$	92,540	 	$	76,194	 	
General and administrative expenses	 	 	9,404	 	 	31,243	 	
Interest	 	 	9,327	 	 	17,247	 	
Income taxes	 	 	2,623	 	 	2,579	 	
Taxes other than income	 	 	3,998	 	 	1,914	 	
Other	 	 	222	 	 	529	 	
 	 	$	118,114	 	$	129,706	 	

Other Income, Net
 
Other income, net consisted of $48.5 million and zero of Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended March 31, 2017 and 2016, respectively.
 
Facilities Insurance Modifications, Net
 
Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility, net of related insurance proceeds.
 
Other Expenses, Net
 
Other expenses, net incurred during the period is comprised of the following:

 	Three Months Ended March 31,	 	
 	2017	    	2016	 	
 	(In thousands)	 	
Inventory write-off	 	 —	 	 	15,709	 	
(Gain) loss on insurance settlements	 	(461)	 	 	(956)	 	
Disputed charges and related costs	 	1,230	 	 	 —	 	
Other, net	 	(7)	 	 	(20)	 	
Other expenses, net	$	762	 	$	14,733	 	
 
The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputes that these expenditures are chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.

 

 
 
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2016, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
 
Overview
 
We are a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara.
 
Recent Developments
 
Corporate
 
In March 2017, following the lender’s semi-annual redetermination, the borrowing base under our Facility was $1.3 billion (effective April 1, 2017). The borrowing base calculation includes value related to the Jubilee and TEN fields.
 
During the first quarter of 2017, the LC Facility size was increased to $115.0 million with additional commitments of up to $10.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. In April 2017, we reduced the size of our LC Facility to $70 million.
 
Ghana
 
Jubilee
 
Kosmos and its partners have determined the preferred long-term solution to the turret bearing issue is to convert the FPSO to a permanently spread moored facility, with offloading through a new deepwater Catenary Anchor Leg Mooring (“CALM”) buoy. The partners are now working with the Government of Ghana to amend the field operating philosophy for this field remediation solution. The Jubilee turret remediation work is progressing as planned and the FPSO spread-mooring at its current heading was completed in February 2017. This allowed the tug boats previously required to hold the vessel on a fixed heading to be removed, significantly reducing the cost and complexity of the current operation. The next phase of the remediation work involves modifications to the turret for long-term spread-moored operations. At present, the partnership is evaluating the optimal long-term orientation and to determine if a rotation of the FPSO is necessary. This evaluation is ongoing amongst the partners and the Government of Ghana, and final decisions and approvals are expected in mid-2017. A facility shutdown of up to 12 weeks may be required during 2017. However, significant efforts are ongoing within the partner group to reduce the duration of the shutdown.
 
A deepwater CALM buoy, anticipated to be installed in 2018, is intended to restore full offloading functionality and remove the need for the dynamic positioning shuttle and storage tankers and associated operating costs. Market inquiries are currently ongoing to estimate the cost and schedule for the fabrication and installation of this buoy. This phase of work also requires approval of both the Government of Ghana and the Jubilee Unit partners.
 
The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is being mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos. Both LOPI and H&M insurance coverages have been confirmed by our insurers and payments are being received. Our LOPI coverage for this incident ends in May 2017.
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Mauritania and Senegal Transactions with BP
 
In December 2016, we announced transactions with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. We believe BP is the optimal partner to advance the gas developments in these blocks and to move forward a multi-well exploration program to fully exploit the hydrocarbon potential of the basin and test its liquids potential, which commenced in March 2017. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in Kosmos BP Senegal Limited (“KBSL”), our majority owned affiliate company which holds a 60% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation’s paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million. However, we have conditionally agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis Corporation by which BP will acquire Timis Corporation’s entire 30% participating interest in the Cayar Offshore Profond and the Saint Louis Offshore Profond blocks offshore Senegal, subject to government approval. Thereafter, KBSL’s participating interest in these blocks will remain at 60%. In the event the transaction between BP and Timis Corporation does not close, then the call option exercise remains valid. In consideration for these transactions, Kosmos received $162 million in cash up front and will receive a $221 million exploration and appraisal carry, up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discovery and prevailing oil prices. These transactions closed in the first quarter of 2017.
 
Mauritania
 
In March 2017, we completed a multi-block 3D seismic survey offshore Mauritania covering approximately 11,700 square kilometers over Blocks C6, C8, C12 and C13. 
 
Senegal (KBSL – equity method investment)
 
In May 2017, we announced the Yakaar-1 exploration well, located in the Cayar Offshore Profond block offshore Senegal, made a major gas discovery. Located approximately 60 miles northwest of Dakar in approximately 2,600 meters of water, the Yakaar-1 exploration well has been drilled to an intermediate depth of approximately 4,700 meters. The well intersected a gross hydrocarbon column of 120 meters (394 feet) in three pools within the primary Lower Cenomanian objective and encountered 45 meters (148 feet) of net pay. The Yakaar-1 exploration well is now drilling to the planned total depth, with results from this section expected in the second quarter of 2017.
 
Sao Tome and Principe
 
In February 2017, we began a 3D seismic survey of approximately 15,800 square kilometers over Blocks 5, 6, 11 and 12 offshore Sao Tome and Principe.  
 
Suriname
 
In January 2017, we completed a 3D seismic survey of approximately 6,500 square kilometers over Block 42 and Block 45 offshore Suriname.
 
Morocco and Western Sahara
 
In February 2017, we began a 3D seismic survey of approximately 9,600 square kilometers over the Boujdour Maritime block in the Aaiun Basin.
 
In April 2017, we began a 3D seismic survey of approximately 3,000 square kilometers over the Essaouira Offshore block in the Agadir Basin.
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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 three months ended March 31, 2017 and 2016 are included in the following table:

 	 	Three Months Ended March 31,	 	
 	 	2017	 	2016	 	
 	 	 	 	 	 	 	 	
Sales volumes:	    	 	 	    	 	 	 	
MBbl	 	 	1,976	 	 	1,896	 	
 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	
Oil sales	 	$	103,432	 	$	62,125	 	
Average sales price per Bbl	 	 	52.34	 	 	32.77	 	
 	 	 	 	 	 	 	 	
Costs:	 	 	 	 	 	 	 	
Oil production, excluding workovers	 	$	19,947	 	$	29,375	 	
Oil production, workovers	 	 	(61)	 	 	17	 	
Total oil production costs	 	$	19,886	 	$	29,392	 	
 	 	 	 	 	 	 	 	
Depletion and depreciation	 	$	34,978	 	$	31,266	 	
 	 	 	 	 	 	 	 	
Average cost per Bbl:	 	 	 	 	 	 	 	
Oil production, excluding workovers	 	$	10.09	 	$	15.49	 	
Oil production, workovers	 	 	(0.03)	 	 	0.01	 	
Total oil production costs	 	 	10.06	 	 	15.50	 	
 	 	 	 	 	 	 	 	
Depletion and depreciation	 	 	17.70	 	 	16.49	 	
Oil production cost and depletion costs	 	$	27.76	 	$	31.99	 	
 
The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of March 31, 2017:

 	 	Actively Drilling or	 	Wells Suspended or	 	
 	 	Completing	 	Waiting on Completion	 	
 	 	Exploration	 	Development	 	Exploration	 	Development	 	
 	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	Gross	 	Net	 	
Ghana	    	 	    	 	    	 	    	 	    	 	    	 	    	 	    	 	 	
Jubilee Unit	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 2	 	0.48	 	
West Cape Three Points	 	 —	 	 —	 	 —	 	 —	 	 9	 	2.78	 	 —	 	 —	 	
TEN	 	 —	 	 —	 	 —	 	 —	 	 —	 	 —	 	 5	 	0.85	 	
Deepwater Tano	 	 —	 	 —	 	 —	 	 —	 	 1	 	0.18	 	 —	 	 —	 	
Mauritania	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
C8	 	 —	 	 —	 	 —	 	 —	 	 3	 	0.84	 	 —	 	 —	 	
Senegal (KBSL - equity method investment)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Saint Louis Offshore Profond	 	 —	 	 —	 	 —	 	 —	 	 1	 	0.30	 	 —	 	 —	 	
Cayar Profond	 	 1	 	0.30	 	 —	 	 —	 	 1	 	0.30	 	 —	 	 —	 	
Total	 	 1	 	0.30	 	 —	 	 —	 	15	 	4.40	 	 7	 	1.33	 	
 
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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.
 
Three months ended March 31, 2017 compared to three months ended March 31, 2016

 	 	Three Months Ended	 	 	 	 	
 	 	March 31,	 	Increase	 	
 	    	2017	    	2016	    	(Decrease)	 	
 	 	(In thousands)	 	
Revenues and other income:	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenue	 	$	103,432	 	$	62,125	 	$	41,307	 	
Other income, net	 	 	48,534	 	 	 8	 	 	48,526	 	
Total revenues and other income	 	 	151,966	 	 	62,133	 	 	89,833	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	
Oil and gas production	 	 	19,886	 	 	29,392	 	 	(9,506)	 	
Facilities insurance modifications, net	 	 	2,574	 	 	 —	 	 	2,574	 	
Exploration expenses	 	 	105,714	 	 	23,858	 	 	81,856	 	
General and administrative	 	 	15,787	 	 	17,920	 	 	(2,133)	 	
Depletion and depreciation	 	 	34,978	 	 	31,266	 	 	3,712	 	
Interest and other financing costs, net	 	 	16,786	 	 	10,324	 	 	6,462	 	
Derivatives, net	 	 	(37,857)	 	 	(4,345)	 	 	(33,512)	 	
Other expenses, net	 	 	762	 	 	14,733	 	 	(13,971)	 	
Total costs and expenses	 	 	158,630	 	 	123,148	 	 	35,482	 	
Loss before income taxes	 	 	(6,664)	 	 	(61,015)	 	 	54,351	 	
Income tax expense (benefit)	 	 	22,177	 	 	(2,022)	 	 	24,199	 	
Net loss	 	$	(28,841)	 	$	(58,993)	 	$	30,152	 	
 
Oil and gas revenue.  Oil and gas revenue increased by $41.3 million as a result of a higher realized price per barrel during the three months ended March 31, 2017, compared to the three months ended March 31, 2016. We lifted and sold 1,976 MBbl at an average realized price per barrel of $52.34 during the three months ended March 31, 2017 and 1,896 MBbl at an average realized price per barrel of $32.77 during the three months ended March 31, 2016.
 
Other income, net.  Other income, net increased by $48.5 million as we recognized $48.5 million of LOPI proceeds, net during the three months ended March 31, 2017 related to the turret bearing issue on the Jubilee FPSO.
 
Oil and gas production.  Oil and gas production costs decreased by $9.5 million during the three months ended March 31, 2017, as compared to the three months ended March 31, 2016 as a result of insurance proceeds received related to turret operating costs during the three months ended March 31, 2017, which offset costs incurred during the same period.
 
Facilities insurance modifications, net. During the three months ended March 31, 2017, we incurred $7.5 million of facilities insurance modifications costs associated with the long-term solution to the turret bearing issue. These costs were mitigated by $4.9 million of insurance proceeds received during the three months ended March 31, 2017.
 
Exploration expenses.  Exploration expenses increased by $81.9 million during the three months ended March 31, 2017, as compared to the three months ended March 31, 2016. The increase is primarily a result of $42.1 million of stacked rig costs associated with the Atwood Achiever in 2017 and a $48.1 million cancellation payment related to the exercise of our election to cancel the fourth year option of the Atwood Achiever drilling rig contract.
 
General and administrative.  General and administrative costs decreased by $2.1 million during the three months ended March 31, 2017, as compared with the three months ended March 31, 2016. The decrease is primarily a result of a decrease in non-cash stock-based compensation and carried costs as a result of the BP transactions.
 
Depletion and depreciation.  Depletion and depreciation increased $3.7 million during the three months ended March 31, 2017, as compared with the three months ended March 31, 2016. The increase is primarily a result of a higher depletion rate during the three months ended March 31, 2017 as a result of a decrease in recognized proved reserves associated with the Jubilee Field in the fourth quarter of 2016.
 
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Interest and other financing costs, net.  Interest and other financing costs, net increased $6.5 million primarily a result of the TEN fields coming online in August 2016, which resulted in a $6.9 million decrease in capitalized interest expense.
 
Derivatives, net.  During the three months ended March 31, 2017 and 2016, we recorded gains of $37.9 million and $4.3 million, respectively, on our outstanding hedge positions. The gains recorded were a result of changes in the forward curve of oil prices during the respective periods.
 
Other expenses, net.  Other expenses, net decreased $14.0 million primarily related to an impairment of inventory recorded in the first quarter of 2016.
 
Income tax expense (benefit).  The Company’s effective tax rates for the three months ended March 31, 2017 and 2016 were 333% and 3%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. The effective tax rate in Ghana is impacted by the timing of non-deductible expenditures incurred associated with the damage to the turret bearing which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. Income tax expense increased $24.2 million during the three months ended March 31, 2017, as compared with March 31, 2016, primarily as a result of higher oil revenue in Ghana.
 
Liquidity and Capital Resources
 
We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margins. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt as well as partner carries. In relation to cash flow generated from our operating activities, if we are unable to continuously export associated natural gas in large quantities, which causes potential production restraints, then the Company’s cash flows from operations will be adversely affected. We have also experienced equipment failures on the FPSOs, as well as the current Jubilee FPSO turret bearing issue. This equipment downtime negatively impacted oil production and we are in the process of repairing the current mechanical issues and implementing a long-term solution for the turret issue.
While we are presently in a strong financial position, a future decline in oil prices, if prolonged, could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. It could also impact the borrowing base available under the Facility or the related debt covenants. Commodity prices are volatile and future prices cannot be accurately predicted. We maintain a hedging program to partially mitigate the price volatility. Our investment decisions are based on longer-term commodity prices based on the long-term nature of our projects and development plans. Also, BP has agreed to partially carry our exploration, appraisal and development program in Mauritania and Senegal over the next several years. Current commodity prices, our hedging program, partner carries and our current liquidity position support our capital program for 2017. As such, our 2017 capital budget is based on our development plans for Ghana and our exploration and appraisal program.
Our future financial condition and liquidity will be impacted by, among other factors, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners and their alignment with respect to capital plans, and the actual cost of exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
In March 2017, following the lender’s semi-annual redetermination, the borrowing base under our Facility was $1.3 billion (effective April 1, 2017). The borrowing base calculation includes value related to the Jubilee and TEN fields.
 
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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 three months ended March 31, 2017 and 2016:

 	 	Three Months Ended	 	
 	 	March 31,	 	
 	    	2017	    	2016	 	
 	 	(In thousands)	 	
Sources of cash, cash equivalents and restricted cash:	 	 	 	 	 	 	 	
Net cash provided by (used in) operating activities	 	$	(30,382)	 	$	15,617	 	
Borrowings under long-term debt	 	 	 —	 	 	150,000	 	
Proceeds on sale of assets	 	 	203,919	 	 	 —	 	
 	 	 	173,537	 	 	165,617	 	
Uses of cash, cash equivalents and restricted cash:	 	 	 	 	 	 	 	
Oil and gas assets	 	 	31,810	 	 	226,571	 	
Other property	 	 	271	 	 	47	 	
Payments on long-term debt	 	 	150,000	 	 	 —	 	
Purchase of treasury stock	 	 	1,115	 	 	1,074	 	
 	 	 	183,196	 	 	227,692	 	
Decrease in cash, cash equivalents and restricted cash	 	$	(9,659)	 	$	(62,075)	 	
 
Net cash provided by (used in) operating activities.  Net cash used in operating activities for the three months ended March 31, 2017 was $30.4 million compared with net cash provided by operating activities for the three months ended March 31, 2016 of $15.6 million. The decrease in cash provided by operating activities in the three months ended March 31, 2017 when compared to the same period in 2016 is primarily a result of an increase in exploration expense  related to the stacked rig costs and rig option cancellation payment as well as a decrease in derivative cash settlements offset by an increase in oil and gas revenue and LOPI proceeds, net.
 
The following table presents our net debt and liquidity as of March 31, 2017:

 	    	March 31, 2017	 	
 	 	(In thousands)	 	
Cash and cash equivalents	 	$	153,194	 	
Restricted cash	 	 	110,342	 	
Senior Notes at par	 	 	525,000	 	
Drawings under the Facility	 	 	700,000	 	
Net debt	 	$	961,464	 	
 	 	 	 	 	
Availability under the Facility(1)	 	$	600,800	 	
Availability under the Corporate Revolver	 	$	400,000	 	
Available borrowings plus cash and cash equivalents	 	$	1,153,994	 	

 	(1)	 	Based on March 31, 2017 redetermination effective April 1, 2017	
 
Capital Expenditures and Investments
 
We expect to incur capital costs as we:
 	·	 	fund asset integrity projects at Jubilee;	
 
 	·	 	execute exploration and appraisal activities in our Senegal and Mauritania license areas; and	
 
 	·	 	acquire and analyze seismic, perform new ventures and manage our rig activities.	
 
We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our participating interests in our prospects including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects, our ability to utilize our available drilling rig capacity, the availability of suitable equipment and qualified personnel and our cash flows
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from operations. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.
 
2017 Capital Program
 
We estimate we will spend approximately $150 million of capital, net of carry amounts related to the Mauritania and Senegal transactions with BP, for the year ending December 31, 2017. Through March 31, 2017, we have spent approximately $120 million which was offset by the initial proceeds from the BP transaction of $222 million resulting in credit to our capital budget of $102 million for the three months ended.
 
This positions us to achieve our objectives and invest counter-cyclically while maintaining a strong balance sheet. The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results among other factors. We resumed our previously suspended drilling program during the first quarter of 2017. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and the prices we receive from the sale of oil, our ability to effectively hedge future production volumes, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners’ alignment with respect to capital plans, and the actual cost of exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
 
Significant Sources of Capital
 
Facility
 
In March 2014, we amended and restated the commercial debt facility (the “Facility”) with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.
 
In March 2017, following the lender’s semi-annual redetermination, the borrowing base under our Facility was $1.3 billion (effective April 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields.
 
We were in compliance with the financial covenants contained in the Facility as of March 31, 2017 (the most recent assessment date). The Facility contains customary cross default provisions.
 
Corporate Revolver
 
In June 2015, we amended and restated the Corporate Revolver from a number of financial institutions, increasing the borrowing capacity to $400.0 million. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs.
 
As of March 31, 2017, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million.
 
We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2017 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
 
Revolving Letter of Credit Facility
 
In July 2016, we amended and restated the revolving letter of credit facility agreement (“LC Facility”), extending the maturity date to July 2019. As of March 31, 2017, the LC Facility size was $115.0 million with additional commitments
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of up to $10.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments include increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. As of March 31, 2017, there were 11 outstanding letters of credit totaling $112.8 million under the LC Facility. The LC Facility contains customary cross default provisions. In April 2017, we reduced the size of our LC Facility to $70 million.

7.875% Senior Secured Notes due 2021
 
During August 2014, we issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
 
During April 2015, we issued an additional $225.0 million Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
 
The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” section of our annual report on Form 10-K for the terms of the Senior Notes.
 
Contractual Obligations
 
The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2017:

 	 	Payments Due By Year(5)	 	
 	 	Total	 	2017(6)	 	2018	 	2019	 	2020	 	2021	 	Thereafter	 	
 	 	(In thousands)	 	
Principal debt repayments(1)	    	$	1,225,000	   	$	 —	  	$	 —	 	$	100,377	 	$	404,971	 	$	719,652	 	$	 —	 	
Interest payments on long-term debt(2)	 	 	337,268	 	 	56,542	 	 	86,962	 	 	80,225	 	 	68,198	 	 	45,341	 	 	 —	 	
Operating leases(3)	 	 	12,568	 	 	3,963	 	 	4,600	 	 	3,940	 	 	65	 	 	 —	 	 	 —	 	
Atwood Achiever drilling rig contract(4)	 	 	133,875	 	 	133,875	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	

 	(1)	 	Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of March 31, 2017, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would	
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impact the scheduled maturities of debt during the next five years and thereafter. As of March 31, 2017, 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 the interest on the Senior Notes.	
 
 	(3)	 	Primarily relates to corporate office and foreign office leases.	
 
 	(4)	 	In January 2017, Kosmos Energy Ventures (“KEV”) exercised its option to cancel the fourth year and revert to the original day rate of approximately $0.6 million per day and original agreement end date in November 2017. Commitments were calculated using the original day rate of $0.6 million, excluding applicable taxes.	
 
 	(5)	 	Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts.	
 
 	(6)	 	Represents the period from April 1, 2017 through December 31, 2017.	
 
We currently have a commitment to drill two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to their maximum $221 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Sao Tome and Principe, Morocco and Western Sahara, we have 3D seismic requirements of 4,750 square kilometers, 3,000 square kilometers and 5,000 square kilometers, respectively. Additionally, in Morocco certain geological studies are also required.
 
The following table presents maturities by expected debt maturity dates, the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the debt’s estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Asset	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(Liability)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Fair Value at	 	
 	 	 	 	Years Ending December 31,	 	March 31,	 	
 	    	2017(5)	    	2018	 	2019	 	2020	 	2021	 	Thereafter	    	2017	 	
 	 	 	 	 	(In thousands, except percentages)	 	
Fixed rate debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior Notes	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	525,000	 	$	 —	 	$	(529,594)	 	
Fixed interest rate	 	 	7.88	%  	 	7.88	%  	 	7.88	%  	 	7.88	%  	 	7.88	%  	 	 —	 	 	 	 	
Variable rate debt:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Facility(1)	 	$	 —	 	$	 —	 	$	100,377	 	$	404,971	 	$	194,652	 	$	 —	 	$	(700,000)	 	
Weighted average interest rate(2)	 	 	4.42	%  	 	5.21	%  	 	5.68	%  	 	6.37	%  	 	6.80	%  	 	 —	 	 	 	 	
Capped interest rate swaps:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notional debt amount	 	$	200,000	 	$	200,000	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	608	 	
Cap	 	 	3.00	%  	 	3.00	%  	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 	 	
Average fixed rate payable(3)	 	 	1.23	%  	 	1.23	%  	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 	 	
Variable rate receivable(4)	 	 	1.17	%  	 	1.61	%  	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 	 	

 	(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 March 31, 2017. Any increases or decreases in the level of borrowings	
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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 March 31, 2017, there were no borrowings under the Corporate Revolver.	
 
 	(2)	 	Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver.	
 
 	(3)	 	We expect to pay the fixed rate if 1-month LIBOR is below the cap, and pay the market rate less the spread between the cap and the fixed rate if LIBOR is above the cap, net of the capped interest rate swaps.	
 
 	(4)	 	Based on implied forward rates in the yield curve at the reporting date.	
 
 	(5)	 	Represents the period April 1, 2017 through December 31, 2017.	

Off-Balance Sheet Arrangements
 
As of March 31, 2017, our material off-balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.
 
Critical Accounting Policies
 
We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and natural gas reserves, asset retirement obligations and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended December 31, 2016, other than as follows:
 
Consolidations / Equity Method of Accounting
 
The Consolidated Financial Statements include the accounts of our wholly-owned subsidiaries. They also include Kosmos’ share of the undivided interest in certain assets, liabilities, revenues and expenses. Investments in corporate joint ventures, which we exercise significant influence over, are accounted for using the equity method of accounting.
 
Equity method investments are integral to our operations. The other parties, who also have an equity interest in these companies, are independent third parties. Kosmos does not invest in these companies in order to remove liabilities from its balance sheet.   
 
Cautionary Note Regarding Forward-looking Statements
 
This quarterly report on Form 10-Q contains estimates and forward-looking statements, principally in “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 quarterly report on Form 10-Q and our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this quarterly report on Form 10-Q, the annual report on Form 10-K and the documents that we have filed with the Securities and Exchange Commission 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;	
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 	·	 	uncertainties inherent in making estimates of our oil and natural gas data;	

 	·	 	the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;	

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

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

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

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

 	·	 	the volatility of oil and natural gas prices;	

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

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

 	·	 	other competitive pressures;	

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

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

 	·	 	cost of compliance with laws and regulations;	

 	·	 	changes in environmental, health and safety or climate change or greenhouse gas (“GHG”) laws and regulations or the implementation, or interpretation, of those laws and regulations;	

 	·	 	adverse effects of sovereign boundary disputes in the jurisdictions in which we operate, including an ongoing maritime boundary demarcation dispute between Cote d’Ivoire and Ghana impacting our operations in the Deepwater Tano Block offshore Ghana;	

 	·	 	environmental liabilities;	

 	·	 	geological, geophysical and other technical and operations, including drilling and oil and gas production and processing;	

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

 	·	 	the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements;	

 	·	 	our vulnerability to severe weather events;	

 	·	 	our ability to meet our obligations under the agreements governing our indebtedness;	

 	·	 	the availability and cost of financing and refinancing our indebtedness;	

 	·	 	the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit and other secured debt;	

 	·	 	the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;	

 	·	 	our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and	

 	·	 	other risk factors discussed in the “Item 1A. Risk Factors” section of this quarterly report on Form 10-Q and our 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 quarterly report on Form 10-Q 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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Item 3. Qualitative and Quantitative Disclosures About Market Risk
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate.
 
We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data — Note 2 — Accounting Policies, Note 8 — Derivative Financial Instruments and Note 9 — Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.
 
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the three months ended March 31, 2017:

 	 	Derivative Contracts Assets (Liabilities)	 	
 	    	Commodities	    	Interest Rates	    	Total	 	
 	 	(In thousands)	 	
Fair value of contracts outstanding as of December 31, 2016	 	$	1,638	 	$	53	 	$	1,691	 	
Changes in contract fair value	 	 	37,849	 	 	328	 	 	38,177	 	
Contract maturities	 	 	(11,380)	 	 	227	 	 	(11,153)	 	
Fair value of contracts outstanding as of March 31, 2017	 	$	28,107	 	$	608	 	$	28,715	 	
 
Commodity Price Risk
 
The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Our oil sales are indexed against Dated Brent crude, prices during the three months ended March 31, 2017 ranged between $49.21 and $56.30.
 
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 four-way collars, three-way collars, put options, call options and swaps. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.
 
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Commodity Price Sensitivity
 
The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of March 31, 2017. Volumes are net of any offsetting derivatives entered into.

 	 	 	 	 	 	Weighted Average Dated Brent Price per Bbl	 	Asset (Liability)	 	
 	  	 	 	 	   	Deferred	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	Fair Value at	 	
 	 	 	 	 	 	Premium	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	March 31,	 	
Term	 	Type of Contract	 	MBbl	 	Payable, Net	 	Swap	 	Sold Put	 	Floor	 	Ceiling	 	Call	 	2017(2)	 	
2017:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
April — December	 	Swap with puts/calls	 	1,505	 	$	2.13	 	$	72.50	 	$	55.00	 	$	 —	 	$	 —	 	$	90.00	 	$	18,887	 	
April — December	 	Swap with puts	 	1,505	 	 	 —	 	 	64.95	 	 	50.00	 	 	 —	 	 	 —	 	 	 —	 	 	14,112	 	
April — December	 	Three-way collars	 	2,012	 	 	2.57	 	 	 —	 	 	30.00	 	 	45.00	 	 	57.50	 	 	 —	 	 	(7,906)	 	
April — December	 	Sold calls(1)	 	1,500	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	85.00	 	 	 —	 	 	(5)	 	
2018:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Three-way collars	 	2,913	 	$	0.74	 	$	 —	 	$	41.57	 	$	56.57	 	$	65.90	 	$	 —	 	$	8,097	 	
January — December	 	Four-way collars	 	2,000	 	 	0.93	 	 	 —	 	 	40.00	 	 	50.00	 	 	61.00	 	 	70.00	 	 	123	 	
January — December	 	Sold calls(1)	 	2,000	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	65.00	 	 	 —	 	 	(4,298)	 	
2019:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
January — December	 	Sold calls(1)	 	913	 	$	 —	 	$	 —	 	$	 —	 	$	 —	 	$	80.00	 	$	 —	 	$	(903)	 	

 	(1)	 	Represents call option contracts sold to counterparties to enhance other derivative positions.	
 
 	(2)	 	Fair values are based on the average forward Dated Brent oil prices on March 31, 2017 which by year are: 2017 — $53.41, 2018 — $53.48 and  2019 — $53.08. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on May 1, 2017 market quotes by year are: 2017 — $51.53, 2018 — $52.07 and 2019 — $51.97.	
 
In April 2017, we entered into three-way collar contracts for 1.0 MMBbl from January 2018 through December 2018 with a floor price of $50.00 per barrel, and a ceiling price of $62.00 per barrel and a purchased call price of $70.00 per barrel. The contracts are indexed to Dated Brent prices and have a weighted average deferred premium payable of $2.15 per barrel.
 
In May 2017, we sold 1.0 MMBbl of put contracts from January 2018 through December 2018 with a strike price of $40.00 per barrel. We used part of the proceeds to increase the ceiling for 1.0 MMBbl of sold calls in the second half of 2017 from $55.00 to $60.00. These contracts are indexed to Dated Brent prices.
 
At March 31, 2017, our open commodity derivative instruments were in a net asset position of $28.1 million. As of March 31, 2017, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $37.5 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $30.5 million.
 
Interest Rate Derivative Instruments
 
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations” section of our annual report on Form 10-K for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.
 
Interest Rate Sensitivity
 
At March 31, 2017, we had indebtedness outstanding under the Facility of $700.0 million, of which $500.0 million bore interest at floating rates after consideration of our fixed rate interest rate hedges. The interest rate on this indebtedness as of March 31, 2017 was approximately 4.0%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.4 million in interest expense per year on the Facility. We pay commitment fees on the undrawn availability and unavailable commitments under the Facility and on the undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.
 
As of March 31, 2017, the fair market value of our interest rate swaps was a net liability of approximately $0.6 million. If LIBOR changed by 10%, it would have a negligible impact on the fair market value of our interest rate swaps.
 
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Item 4. 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 March 31, 2017, 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.
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PART II. OTHER INFORMATION
 
Item 1. Legal Proceedings

There have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.
 
Item 1A. Risk Factors
 
There have been no material changes from the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2016. 
 
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
 
Issuer Purchases of Equity Securities
 
Under the terms of our Long Term Incentive Plan (“LTIP”), we have issued restricted shares to our employees. On the date that these restricted shares vest, we provide such employees the option to sell shares to cover their tax liability, via a net exercise provision pursuant to our applicable restricted share award agreements and the LTIP, either the number of vested shares (based on the closing price of our common shares on such vesting date) equal to the minimum statutorily tax liability owed by such grantee or up to the maximum statutory tax liability for such grantee. The Company may repurchase the restricted shares sold by the grantees to settle their tax liability. The repurchased shares are reallocated to the number of shares available for issuance under the LTIP. The following table outlines the total number of restricted shares purchased during the three months ended, March 31, 2017 and the average price paid per share.

 	    	Total Number	    	Average	 	
 	 	of Shares	 	Price Paid	 	
 	 	Purchased	 	per Share	 	
 	 	(In thousands)	 	 	 	 	
January 1, 2017—January 31, 2017	 	74	 	$	7.01	 	
February 1, 2017—February 28, 2017	 	 —	 	 	 —	 	
March 1, 2017—March 31, 2017	 	 —	 	 	 —	 	
Total	 	74	 	 	 —	 	
 
Item 3.Defaults Upon Senior Securities
 
None.
 
Item 4.Mine Safety Disclosures
 
Not applicable.
 
Item 5.Other Information.
 
There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K, other than as follows:
 
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 March 31, 2017. In addition, except as described below, at the time of filing this quarterly report on Form 10-Q, we are not aware of any such reportable
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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 March 31, 2017, as the case may be, additional reportable transactions may be disclosed by such companies.
 
As of March 31, 2017, funds affiliated with Warburg Pincus (“Warburg Pincus”) held approximately 26% of our outstanding common shares. We are also a party to a shareholders agreement with Warburg Pincus pursuant to which, among other things, Warburg Pincus currently has the right to designate two members of our board of directors. Accordingly, Warburg Pincus may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended March 31, 2017.
 
Disclosure relating to Warburg Pincus and its affiliates
 
Warburg Pincus informed us of the information reproduced below (the “SAMIH Disclosure”) regarding Santander Asset Management Investment Holdings Limited (“SAMIH”). SAMIH is a company that may be considered an affiliate of Warburg Pincus. Because we and SAMIH may be deemed to be controlled by Warburg Pincus, we may be considered an “affiliate” of SAMIH for the purposes of Section 13(r) of the Exchange Act.
 
SAMIH Disclosure:
 
Quarter ended March 31, 2017
 
Santander UK plc (“Santander UK”) holds two savings accounts and one current account for two customers resident in the United Kingdom (“UK”) who are currently designated by the United States (“US”) under the Specially Designated Global Terrorist (“SDGT”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the first quarter of calendar year 2017 were negligible relative to the overall revenues and profits of Banco Santander SA.
 
Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the first quarter of calendar year 2017. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. No revenues or profits were generated by Santander UK on this account in the first quarter of calendar year 2017.
 
Item 6. Exhibits
 
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10-Q.
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SIGNATURES
 
Pursuant to the requirements 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.	
 	 	(Registrant)	
 	 	 	
Date	May 8, 2017	 	/s/ THOMAS P. CHAMBERS	
 	 	Thomas P. Chambers	
 	 	Senior Vice President and Chief Financial Officer	
 	 	(Principal Financial Officer)	
 
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INDEX OF EXHIBITS

Exhibit
Number	 	Description of Document	
10.1*	 	Offer Letter, dated November 2, 2014, between Kosmos Energy, LLC and Michael Anderson	
 	 	 	
10.2*	 	Kosmos Energy Deferred Compensation Plan (effective February 1, 2017)	
 	 	 	
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.	
 	 	 	
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.

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Exhibit 10.1

November 2, 2014
Michael James Anderson
47 Links Road, Epsom,
Surrey, KT 17 3PP
Dear Mike:
On behalf of Kosmos Energy, LLC (the “Company”) I am pleased to present this Offer of Employment (this “ Offer ”) which sets out the key terms our offer of employment to you in the position of Senior Vice President, Government and External Affairs, as follows:
Start Date	On or before 9th March, 2015 (the “Start Date”).	
Base Salary
 	Base salary of $350,000 (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.	
Signing Bonus
 	A signing bonus of $100,000 will be paid in your first paycheck.  Should you voluntarily terminate your employment for any reason within the first 12 months of employment or are terminated for cause at the sole discretion of the Company, you shall reimburse the Company for your signing bonus.	
Annual Target Cash Bonus	Annual discretionary cash bonus that will be targeted at 75% of the Base Salary (the “ Target Bonus ”). The actual cash bonus that you would receive for any year may range between 0% and 200% of your Base Salary, based upon both Company and individual performance.	
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 ”) with an aggregate value as of the grant date of $818,750. Of this amount, $359,375 will be granted in the form of service-vesting RSUs and $459,375 will be granted in the form of performance-vesting RSUs. The number of common shares of Kosmos Energy Ltd. 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 Kosmos Energy Ltd. Long Term Incentive Plan (“ LTIP ”) by dividing the grant date value of such award by the closing price of a common share on the grant date.	

 

Relocation	You will be required to relocate your principal residence to the Dallas/Fort Worth area within three years from the Start Date. The Company will pay or reimburse you for all reasonable and customary costs associated with the following:
·for a period of up to twelve (12) months from your Start Date your reasonable and necessary temporary housing expenses in the Dallas/Fort Worth area.
·for a period of up to three (3) years from your Start Date, your reasonable travel expenses for a round trip each calendar quarter between Dallas, Texas and the United Kingdom. However, if you are required to travel to the United Kingdom on business, then said business trip shall count as your one paid trip in that quarter.
·Further, you will receive a transition payment of $100,000 in your first paycheck to cover your estimated immediate costs of transitioning between the United Kingdom and Dallas, Texas.
In addition, in line with other executive officers the Company will cover the costs of the following items to facilitate your move from the United Kingdom to Dallas:
·Packing and transporting standard furniture and personal effects belonging to you and members of your immediate family.
·Reasonable expenses, including travel, for up to seven days 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.
·Also, should you own a home in your current location, you may be eligible for either option A or B below, as circumstances require and subject to pre-approval by the Company:
A.  Existing Home Lease Cost Reimbursement: After you and, if applicable your family, relocate to the Dallas/Fort Worth area, the Company will pay or reimburse you for your out of pocket ownership costs during any period in which your home is not leased, subject to a maximum of $3,000 per month, and further subject to a maximum reimbursement period of six (6) months.
B.  Existing Home Sale Lump Sum: The company will pay you a one-time lump sum of $50,000 in lieu of costs associated with the sale of your existing home in the United Kingdom 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 payment.	
 
2

 

401(k) Plan	You will be eligible to participate in the Company’s 401(k) plan starting on the 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.	
Other Benefits	You will be entitled to participate in the Company’s other benefit plans applicable to full-time regular employees. For the 2013 calendar year, the Company is paying 100% of the cost of such benefit plans.	
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 and career development workshops.	
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 practice at any time in its sole discretion. 	
Severance and/or Change in Control	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 for reasons other than a change in control, then in consideration for signing a binding settlement and release agreement, you will receive a severance payment equal  to your then current base salary plus target bonus plus Target Bonus for 1 year. Additionally, the Company  will  reimburse you the amount of COBRA payment to cover medical and dental health insurance for you and your dependents for 1 year. 
 
Terminations resulting from a change in control are addressed pursuant to the Company’s Change in Control policy subject to subsequent amendment or termination of such policy.  The policy can be  located on the Edgar website at the following link:  http://www.sec.gov/Archives/edgar/data/1509991/000095010313007481/0000950103-13-007481-index.htm

3

 

 	Sincerely,	
 	 	
 	/s/ Andrew G. Inglis	
 	Andrew G. Inglis
Chairman and Chief Executive Officer	
 	 	
 	cc: J.E. Doughty	
 
I agree to the terms of this Offer as set forth above.  Further, I represent to the Company that I am not subject to any obligation or agreement that would prevent me from becoming an employee of the Company or that will adversely impact my ability to perform my duties.
/s/ Michael James Anderson	 	
 	 	
Michael James Anderson	 	

28 November 2014	 	
 	 	
Date	 	
 
4

Exhibit 10.2

KOSMOS ENERGY DEFERRED
COMPENSATION PLAN
Effective February 1, 2017
IMPORTANT NOTE
This document has not been approved by the Department of Labor, Internal Revenue Service or any other governmental entity. An adopting Employer must determine whether the Plan is subject to the Federal securities laws and the securities laws of the various states. An adopting Employer may not rely on this document to ensure any particular tax consequences or to ensure that the Plan is “unfunded and maintained primarily for the purpose of providing deferred compensation to a select group of management or highly compensated employees” under Title I of the Employee Retirement Income Security Act of 1974, as amended, with respect to the Employer’s particular situation. Fidelity Employer Services Company, its affiliates and employees cannot provide you with legal advice in connection with the execution of this document. This document should be reviewed by the Employer’s attorney prior to execution.
March 2012

 

TABLE OF CONTENTS
PREAMBLE	

ARTICLE 1 – GENERAL	
1.1	Plan	
1.2	Effective Dates	
1.3	Amounts Not Subject to Code Section 409A	

ARTICLE 2 - DEFINITIONS	
2.1	Account	
2.2	Administrator	
2.3	Adoption Agreement	
2.4	Beneficiary	
2.5	Board or Board of Directors	
2.6	Bonus	
2.7	Change in Control	
2.8	Code	
2.9	Compensation	
2.10	Director	
2.11	Disability	
2.12	Eligible Employee	
2.13	Employer	
2.14	ERISA	
2.15	Identification Date	
2.16	Key Employee	
2.17	Participant	
2.18	Plan	
2.19	Plan Sponsor	
2.20	Plan Year	
2.21	Related Employer	
2.22	Retirement	
2.23	Separation from Service	
2.24	Unforeseeable Emergency	
2.25	Valuation Date	
2.26	Years of Service	

ARTICLE 3 - PARTICIPATION	
3.1	Participation	
3.2	Termination of Participation	

i

 

ARTICLE 4 – PARTICIPANT ELECTIONS	
4.1	Deferral Agreement	
4.2	Amount of Deferral	
4.3	Timing of Election to Defer	
4.4	Election of Payment Schedule and Form of Payment	

ARTICLE 5 – EMPLOYER CONTRIBUTIONS	
5.1	Matching Contributions	
5.2	Other Contributions	

ARTICLE 6 – ACCOUNTS AND CREDITS	
6.1	Establishment of Account	
6.2	Credits to Account	

ARTICLE 7 – INVESTMENT OF CONTRIBUTIONS	
7.1	Investment Options	
7.2	Adjustment of Accounts	

ARTICLE 8 – RIGHT TO BENEFITS	
8.1	Vesting	
8.2	Death	
8.3	Disability	

ARTICLE 9 – DISTRIBUTION OF BENEFITS	
9.1	Amount of Benefits	
9.2	Method and Timing of Distributions	
9.3	Unforeseeable Emergency	
9.4	Payment Election Overrides	
9.5	Cashouts of Amounts Not Exceeding Stated Limit	
9.6	Required Delay in Payment to Key Employees	
9.7	Change in Control	
9.8	Permissible Delays in Payment	
9.9	Permitted Acceleration of Payment	
 
ii

 

ARTICLE 10 — AMENDMENT AND TERMINATION	
10.1	Amendment by Plan Sponsor	
10.2	Plan Termination Following Change in Control or Corporate Dissolution	
10.3	Other Plan Terminations	

ARTICLE 11 — THE TRUST	
11.1	Establishment of Trust	
11.2	Rabbi Trust	
11.3	Investment of Trust Funds	

ARTICLE 12 — PLAN ADMINISTRATION	
12.1	Powers and Responsibilities of the Administrator	
12.2	Claims and Review Procedures	
12.3	Plan Administrative Costs	

ARTICLE 13 — MISCELLANEOUS	
13.1	Unsecured General Creditor of the Employer	
13.2	Employer’s Liability	
13.3	Limitation of Rights	
13.4	Anti-Assignment	
13.5	Facility of Payment	
13.6	Notices	
13.7	Tax Withholding	
13.8	Indemnification	
13.9	Successors	
13.10	Disclaimer	
13.11	Governing Law	

iii

 

PREAMBLE
The Plan is intended to be a “plan which is unfunded and is maintained by an employer primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees” within the meaning of Sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income Security Act of 1974, as amended, or an “excess benefit plan” within the meaning of Section 3(36) of the Employee Retirement Income Security Act of 1974, as amended, or a combination of both. The Plan is further intended to conform with the requirements of Internal Revenue Code Section 409A and the final regulations issued thereunder and shall be interpreted, implemented and administered in a manner consistent therewith.

 

 

ARTICLE 1 – GENERAL
1.1      Plan. The Plan will be referred to by the name specified in the Adoption Agreement.
1.2      Effective Dates.
(a)       Original Effective Date. The Original Effective Date is the date as of which the Plan was initially adopted.
(b)       Amendment Effective Date. The Amendment Effective Date is the date specified in the Adoption Agreement as of which the Plan is amended and restated. Except to the extent otherwise provided herein or in the Adoption Agreement, the Plan shall apply to amounts deferred and benefit payments made on or after the Amendment Effective Date.
(c)       Special Effective Date. A Special Effective Date may apply to any given provision if so specified in Appendix A of the Adoption Agreement. A Special Effective Date will control over the Original Effective Date or Amendment Effective Date, whichever is applicable, with respect to such provision of the Plan.
1.3      Amounts Not Subject to Code Section 409A
Except as otherwise indicated by the Plan Sponsor in Section 1.01 of the Adoption Agreement, amounts deferred before January 1, 2005 that are earned and vested on December 31, 2004 will be separately accounted for and administered in accordance with the terms of the Plan as in effect on December 31, 2004.

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ARTICLE 2 – DEFINITIONS
Pronouns used in the Plan are in the masculine gender but include the feminine gender unless the context clearly indicates otherwise. Wherever used herein, the following terms have the meanings set forth below, unless a different meaning is clearly required by the context:
2.1     “Account” means an account established for the purpose of recording amounts credited on behalf of a Participant and any income, expenses, gains, losses or distributions included thereon. The Account shall be a bookkeeping entry only and shall be utilized solely as a device for the measurement and determination of the amounts to be paid to a Participant or to the Participant’s Beneficiary pursuant to the Plan.
2.2     “Administrator” means the person or persons designated by the Plan Sponsor in Section 1.05 of the Adoption Agreement to be responsible for the administration of the Plan. If no Administrator is designated in the Adoption Agreement, the Administrator is the Plan Sponsor.
2.3     “Adoption Agreement” means the agreement adopted by the Plan Sponsor that establishes the Plan.
2.4     “Beneficiary” means the persons, trusts, estates or other entities entitled under Section 8.2 to receive benefits under the Plan upon the death of a Participant.
2.5     “Board” or “Board of Directors” means the Board of Directors of the Plan Sponsor.
2.6     “Bonus” means an amount of incentive remuneration payable by the Employer to a Participant.
2.7     “Change in Control” has the meaning set forth in the Kosmos Energy Ltd. Long Term Incentive Plan (as amended from time to time).
2.8     “Code” means the Internal Revenue Code of 1986, as amended.
2.9     “Compensation” has the meaning specified in Section 3.01 of the Adoption Agreement.
2.10   “Director” means a non-employee member of the Board who has been designated by the Employer as eligible to participate in the Plan.
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2.11  “Disability” means a determination by the Administrator that the Participant is either (a) unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (b) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or last for a continuous period of not less than twelve months, receiving income replacement benefits for a period of not less than three months under an accident and health plan covering employees of the Employer. A Participant will be considered to have incurred a Disability if he is determined to be totally disabled by the Social Security Administration or the Railroad Retirement Board.
2.12   “Eligible Employee” means an employee of the Employer who satisfies the requirements in Section 2.01 of the Adoption Agreement.
2.13   “Employer” means the Plan Sponsor and any other entity which is authorized by the Plan Sponsor to participate in and, in fact, does adopt the Plan.
2.14   “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.
2.15   “Identification Date” means the date as of which Key Employees are determined which is specified in Section 1.06 of the Adoption Agreement.
2.16   “Key Employee” means an employee who satisfies the conditions set forth in Section 9.6.
2.17   “Participant” means an Eligible Employee or Director who commences participation in the Plan in accordance with Article 3.
2.18   “Plan” means the unfunded plan of deferred compensation set forth herein, including the Adoption Agreement and any trust agreement, as adopted by the Plan Sponsor and as amended from time to time.
2.19   “Plan Sponsor” means the entity identified in Section 1.03 of the Adoption Agreement or any successor by merger, consolidation or otherwise.
2.20   “Plan Year” means the period identified in Section 1.02 of the Adoption Agreement.
2.21   “Related Employer” means the Employer and (a) any corporation that is a member of a controlled group of corporations as defined in Code Section 414(b) that includes the Employer and (b) any trade or business that is under common control as defined in Code Section 414(c) that includes the Employer.
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2.22   “Retirement” has the meaning specified in 6.01(f) of the Adoption Agreement.
2.23   “Separation from Service” means the date that the Participant dies, retires or otherwise has a termination of employment with respect to all entities comprising the Related Employer. A Separation from Service does not occur if the Participant is on military leave, sick leave or other bona fide leave of absence if the period of leave does not exceed six months or such longer period during which the Participant’s right to re‑employment is provided by statute or contract. If the period of leave exceeds six months and the Participant’s right to re-employment is not provided either by statute or contract, a Separation from Service will be deemed to have occurred on the first day following the six-month period. If the period of leave is due to any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than six months, where the impairment causes the Participant to be unable to perform the duties of his or her position of employment or any substantially similar position of employment, a 29 month period of absence may be substituted for the six month period.
Whether a termination of employment has occurred is based on whether the facts and circumstances indicate that the Related Employer and the Participant reasonably anticipated that no further services would be performed after a certain date or that the level of bona fide services the Participant would perform after such date (whether as an employee or as an independent contractor) would permanently decrease to no more than 20 percent of the average level of bona fide services performed (whether as an employee or an independent contractor) over the immediately preceding 36 month period (or the full period of services to the Related Employer if the employee has been providing services to the Related Employer for less than 36 months).
An independent contractor is considered to have experienced a Separation from Service with the Related Employer upon the expiration of the contract (or, in the case of more than one contract, all contracts) under which services are performed for the Related Employer if the expiration constitutes a good-faith and complete termination of the contractual relationship.
If a Participant provides services as both an employee and an independent contractor of the Related Employer, the Participant must separate from service both as an employee and as an independent contractor to be treated as having incurred a Separation from Service. If a Participant ceases providing services as an independent contractor and begins providing services as an employee, or ceases providing services as an employee and begins providing services as an independent
2-3

 

contractor, the Participant will not be considered to have experienced a Separation from Service until the Participant has ceased providing services in both capacities.
If a Participant provides services both as an employee and as a member of the board of directors of a corporate Related Employer (or an analogous position with respect to a noncorporate Related Employer), the services provided as a director are not taken into account in determining whether the Participant has incurred a Separation from Service as an employee for purposes of a nonqualified deferred compensation plan in which the Participant participates as an employee that is not aggregated under Code Section 409A with any plan in which the Participant participates as a director.
If a Participant provides services both as an employee and as a member of the board of directors of a corporate related Employer (or an analogous position with respect to a noncorporate Related Employer), the services provided as an employee are not taken into account in determining whether the Participant has experienced a Separation from Service as a director for purposes of a nonqualified deferred compensation plan in which the Participant participates as a director that is not aggregated under Code Section 409A with any plan in which the Participant participates as an employee.
All determinations of whether a Separation from Service has occurred will be made in a manner consistent with Code Section 409A and the final regulations thereunder.
2.24  “Unforeseeable Emergency” means a severe financial hardship of the Participant resulting from an illness or accident of the Participant, the Participant’s spouse, the Participant’s Beneficiary, or the Participant’s dependent (as defined in Code Section 152, without regard to Code section 152(b)(1), (b)(2) and (d)(1)(B); loss of the Participant’s property due to casualty; or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant.
2.25   “Valuation Date” means each business day of the Plan Year that the New York Stock Exchange is open.
2.26   “Years of Service” means each one year period for which the Participant receives service credit in accordance with the provisions of Section 7.01(d) of the Adoption Agreement.

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ARTICLE 3 — PARTICIPATION
3.1      Participation. The Participants in the Plan shall be those Directors and employees of the Employer who satisfy the requirements of Section 2.01 of the Adoption Agreement.
3.2     Termination of Participation. The Administrator may terminate a Participant’s participation in the Plan in a manner consistent with Code Section 409A. If the Employer terminates a Participant’s participation before the Participant experiences a Separation from Service the Participant’s vested Accounts shall be paid in accordance with the provisions of Article 9.

3-1

 

ARTICLE 4 — PARTICIPANT ELECTIONS
4.1      Deferral Agreement. If permitted by the Plan Sponsor in accordance with Section 4.01 of the Adoption Agreement, each Eligible Employee and Director may elect to defer his Compensation within the meaning of Section 3.01 of the Adoption Agreement by executing in writing or electronically, a deferral agreement in accordance with rules and procedures established by the Administrator and the provisions of this Article 4.
A new deferral agreement must be timely executed for each Plan Year during which the Eligible Employee or Director desires to defer Compensation. An Eligible Employee or Director who does not timely execute a deferral agreement shall be deemed to have elected zero deferrals of Compensation for such Plan Year.
A deferral agreement may be changed or revoked during the period specified by the Administrator. Except as provided in Section 9.3 or in Section 4.01(c) of the Adoption Agreement, a deferral agreement becomes irrevocable at the close of the specified period.
4.2      Amount of Deferral. An Eligible Employee or Director may elect to defer Compensation in any amount permitted by Section 4.01(a) of the Adoption Agreement.
4.3      Timing of Election to Defer. Each Eligible Employee or Director who desires to defer Compensation otherwise payable during a Plan Year must execute a deferral agreement within the period preceding the Plan Year specified by the Administrator. Each Eligible Employee who desires to defer Compensation that is a Bonus must execute a deferral agreement within the period preceding the Plan Year during which the Bonus is earned that is specified by the Administrator, except that if the Bonus can be treated as performance based compensation as described in Code Section 409A(a)(4)(B)(iii), the deferral agreement may be executed within the period specified by the Administrator, which period, in no event, shall end after the date which is six months prior to the end of the period during which the Bonus is earned, provided the Participant has performed services continuously from the later of the beginning of the performance period or the date the performance criteria are established through the date the Participant executed the deferral agreement and provided further that the compensation has not yet become ‘readily ascertainable’ within the meaning of Reg. Sec 1.409A‑2(a)(8). In addition, if the Compensation qualifies as ‘fiscal year compensation’ within the meaning of Reg. Sec. 1.409A‑2(a)(6), the deferral agreement may be made not later than the
4-1

 

end of the Employer’s taxable year immediately preceding the first taxable year of the Employer in which any services are performed for which such Compensation is payable.
Except as otherwise provided below, an employee who is classified or designated as an Eligible Employee during a Plan Year or a Director who is designated as eligible to participate during a Plan Year may elect to defer Compensation otherwise payable during the remainder of such Plan Year in accordance with the rules of this Section 4.3 by executing a deferral agreement within the thirty (30) day period beginning on the date the employee is classified or designated as an Eligible Employee or the date the Director is designated as eligible, whichever is applicable, if permitted by Section 4.01(b)(ii) of the Adoption Agreement. If Compensation is based on a specified performance period that begins before the Eligible Employee or Director executes his deferral agreement, the election will be deemed to apply to the portion of such Compensation equal to the total amount of Compensation for the performance period multiplied by the ratio of the number of days remaining in the performance period after the election becomes irrevocable and effective over the total number of days in the performance period. The rules of this paragraph shall not apply unless the Eligible Employee or Director can be treated as initially eligible in accordance with Reg. Sec. 1.409A‑2(a)(7).
4.4      Election of Payment Schedule and Form of Payment.
All elections of a payment schedule and a form of payment will be made in accordance with rules and procedures established by the Administrator and the provisions of this Section 4.4.
(a)If the Plan Sponsor has elected to permit annual distribution elections in accordance with Section 6.01(h) of the Adoption Agreement the following rules apply. At the time an Eligible Employee or Director completes a deferral agreement, the Eligible Employee or Director must elect a distribution event (which includes a specified time) and a form of payment for the Compensation subject to the deferral agreement from among the options the Plan Sponsor has made available for this purpose and which are specified in 6.01(b) of the Adoption Agreement. Prior to the time required by Reg. Sec. 1.409A‑2, the Eligible Employee or Director shall elect a distribution event (which includes a specified time) and a form of payment for any Employer contributions that may be credited to the Participant’s Account during the Plan Year. If an Eligible Employee or Director fails to elect a distribution event, he shall be deemed to have elected Separation from Service as the distribution event. If he fails to elect a form of payment, he shall be deemed to have elected a lump sum form of payment.
4-2

 

(b)If the Plan Sponsor has elected not to permit annual distribution elections in accordance with Section 6.01(h) of the Adoption Agreement the following rules apply. At the time an Eligible Employee or Director first completes a deferral agreement but in no event later than the time required by Reg. Sec. 1.409A‑2, the Eligible Employee or Director must elect a distribution event (which includes a specified time) and a form of payment for amounts credited to his Account from among the options the Plan Sponsor has made available for this purpose and which are specified in Section 6.01(b) of the Adoption Agreement. If an Eligible Employee or Director fails to elect a distribution event, he shall be deemed to have elected Separation from Service in the distribution event. If the Eligible Employee or Director fails to elect a form of payment, he shall be deemed to have elected a lump sum form of payment.

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ARTICLE 5 — EMPLOYER CONTRIBUTIONS
5.1      Matching Contributions. If elected by the Plan Sponsor in Section 5.01(a) of the Adoption Agreement, the Employer will credit the Participant’s Account with a matching contribution determined in accordance with the formula specified in Section 5.01(a) of the Adoption Agreement. The matching contribution will be treated as allocated to the Participant’s Account at the time specified in Section 5.01(a)(iii) of the Adoption Agreement.
5.2      Other Contributions. If elected by the Plan Sponsor in Section 5.01(b) of the Adoption Agreement, the Employer will credit the Participant’s Account with a contribution determined in accordance with the formula or method specified in Section 5.01(b) of the Adoption Agreement. The contribution will be treated as allocated to the Participant’s Account at the time specified in Section 5.01(b)(iii) of the Adoption Agreement.

5-1

 

ARTICLE 6 — ACCOUNTS AND CREDITS
6.1      Establishment of Account. For accounting and computational purposes only, the Administrator will establish and maintain an Account on behalf of each Participant which will reflect the credits made pursuant to Section 6.2, distributions or withdrawals, along with the earnings, expenses, gains and losses allocated thereto, attributable to the hypothetical investments made with the amounts in the Account as provided in Article 7. The Administrator will establish and maintain such other records and accounts, as it decides in its discretion to be reasonably required or appropriate to discharge its duties under the Plan.
6.2      Credits to Account. A Participant’s Account will be credited for each Plan Year with the amount of his elective deferrals under Section 4.1 at the time the amount subject to the deferral election would otherwise have been payable to the Participant and the amount of Employer contributions treated as allocated on his behalf under Article 5.

6-1

 

ARTICLE 7 — INVESTMENT OF CONTRIBUTIONS
7.1      Investment Options. The amount credited to each Account shall be treated as invested in the investment options designated for this purpose by the Administrator.
7.2      Adjustment of Accounts. The amount credited to each Account shall be adjusted for hypothetical investment earnings, expenses, gains or losses in an amount equal to the earnings, expenses, gains or losses attributable to the investment options selected by the party designated in Section 9.01 of the Adoption Agreement from among the investment options provided in Section 7.1. If permitted by Section 9.01 of the Adoption Agreement, a Participant (or the Participant’s Beneficiary after the death of the Participant) may, in accordance with rules and procedures established by the Administrator, select the investments from among the options provided in Section 7.1 to be used for the purpose of calculating future hypothetical investment adjustments to the Account or to future credits to the Account under Section 6.2 effective as of the Valuation Date coincident with or next following notice to the Administrator. Each Account shall be adjusted as of each Valuation Date to reflect: (a) the hypothetical earnings, expenses, gains and losses described above; (b) amounts credited pursuant to Section 6.2; and (c) distributions or withdrawals. In addition, each Account may be adjusted for its allocable share of the hypothetical costs and expenses associated with the maintenance of the hypothetical investments provided in Section 7.1.

7-1

 

ARTICLE 8 — RIGHT TO BENEFITS
8.1      Vesting. A Participant, at all times, has a 100% nonforfeitable interest in the amounts credited to his Account attributable to his elective deferrals made in accordance with Section 4.1.
A Participant’s right to the amounts credited to his Account attributable to Employer contributions made in accordance with Article 5 shall be determined in accordance with the relevant schedule and provisions in Section 7.01 of the Adoption Agreement. Upon a Separation from Service and after application of the provisions of Section 7.01 of the Adoption Agreement, the Participant shall forfeit the nonvested portion of his Account.
8.2      Death. The Plan Sponsor may elect to accelerate vesting upon the death of the Participant in accordance with Section 7.01(c) of the Adoption Agreement and/or to accelerate distributions upon Death in accordance with Section 6.01(b) or Section 6.01(d) of the Adoption Agreement. If the
Plan Sponsor does not elect to accelerate distributions upon death in accordance with Section 6.01(b) or Section 6.01(d) of the Adoption Agreement, the vested amount credited to the Participant’s Account will be paid in accordance with the provisions of Article 9.
A Participant may designate a Beneficiary or Beneficiaries, or change any prior designation of Beneficiary or Beneficiaries in accordance with rules and procedures established by the Administrator.
A copy of the death notice or other sufficient documentation must be filed with and approved by the Administrator. If upon the death of the Participant there is, in the opinion of the Administrator, no designated Beneficiary for part or all of the Participant’s vested Account, such amount will be paid to his estate (such estate shall be deemed to be the Beneficiary for purposes of the Plan) in accordance with the provisions of Article 9.
8.3      Disability. If the Plan Sponsor has elected to accelerate vesting upon the occurrence of a Disability in accordance with Section 7.01(c) of the Adoption Agreement and/or to permit distributions upon Disability in accordance with Section 6.01(b) or Section 6.01(d) of the Adoption Agreement, the determination of whether a Participant has incurred a Disability shall be made by the Administrator in its sole discretion in a manner consistent with the requirements of Code Section 409A.
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ARTICLE 9 — DISTRIBUTION OF BENEFITS
9.1      Amount of Benefits. The vested amount credited to a Participant’s Account as determined under Articles 6, 7 and 8 shall determine and constitute the basis for the value of benefits payable to the Participant under the Plan.
9.2      Method and Timing of Distributions. Except as otherwise provided in this Article 9, distributions under the Plan shall be made in accordance with the elections made or deemed made by the Participant under Article 4. Subject to the provisions of Section 9.6 requiring a six month delay for certain distributions to Key Employees, distributions following a payment event shall commence at the time specified in Section 6.01(a) of the Adoption Agreement. If permitted by Section 6.01(g) of the Adoption Agreement, a Participant may elect, at least twelve months before a scheduled distribution event, to delay the payment date for a minimum period of sixty months from the originally scheduled date of payment, provided the election does not take effect for at least twelve months from the date on which the election is made. The distribution election change must be made in accordance with procedures and rules established by the Administrator. The Participant may, at the same time the date of payment is deferred, change the form of payment but such change in the form of payment may not effect an acceleration of payment in violation of Code Section 409A or the provisions of Reg. Sec. 1.409A‑2(b). For purposes of this Section 9.2, a series of installment payments is always treated as a single payment and not as a series of separate payments.
9.3      Unforeseeable Emergency. A Participant may request a distribution due to an Unforeseeable Emergency if the Plan Sponsor has elected to permit Unforeseeable Emergency withdrawals under Section 8.01(a) of the Adoption Agreement. The request must be in writing and must be submitted to the Administrator along with evidence that the circumstances constitute an Unforeseeable Emergency. The Administrator has the discretion to require whatever evidence it deems necessary to determine whether a distribution is warranted, and may require the Participant to certify that the need cannot be met from other sources reasonably available to the Participant. Whether a Participant has incurred an Unforeseeable Emergency will be determined by the Administrator on the basis of the relevant facts and circumstances in its sole discretion, but, in no event, will an Unforeseeable Emergency be deemed to exist if the hardship can be relieved: (a) through reimbursement or compensation by insurance or otherwise, (b) by liquidation of the Participant’s assets to the
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extent such liquidation would not itself cause severe financial hardship, or (c) by cessation of deferrals under the Plan. A distribution due to an Unforeseeable Emergency must be limited to the amount reasonably necessary to satisfy the emergency need and may include any amounts necessary to pay any federal, state, foreign or local income taxes and penalties reasonably anticipated to result from the distribution. The distribution will be made in the form of a single lump sum cash payment. If permitted by Section 8.01(b) of the Adoption Agreement, a Participant’s deferral elections for the remainder of the Plan Year will be cancelled upon a withdrawal due to an Unforeseeable Emergency. If the payment of all or any portion of the Participant’s vested Account is being delayed in accordance with Section 9.6 at the time he experiences an Unforeseeable Emergency, the amount being delayed shall not be subject to the provisions of this Section 9.3 until the expiration of the six month period of delay required by section 9.6.
9.4      Payment Election Overrides. If the Plan Sponsor has elected one or more payment election overrides in accordance with Section 6.01(d) of the Adoption Agreement, the following provisions apply. Upon the occurrence of the first event selected by the Plan Sponsor, the remaining vested amount credited to the Participant’s Account shall be paid in the form designated to the Participant or his Beneficiary regardless of whether the Participant had made different elections of time and /or form of payment or whether the Participant was receiving installment payments at the time of the event.
9.5      Cashouts Of Amounts Not Exceeding Stated Limit. If the vested amount credited to the Participant’s Account does not exceed the limit established for this purpose by the Plan Sponsor in Section 6.01(e) of the Adoption Agreement at the time he incurs a Separation from Service for any reason, the Employer shall distribute such amount to the Participant at the time specified in Section 6.01(a) of the Adoption Agreement in a single lump sum cash payment following such Separation from Service regardless of whether the Participant had made different elections of time or form of payment as to the vested amount credited to his Account or whether the Participant was receiving installments at the time of such termination. A Participant’s Account, for purposes of this Section 9.5, shall include any amounts described in Section 1.3.
9.6      Required Delay in Payment to Key Employees. Except as otherwise provided in this Section 9.6, a distribution made on account of Separation from Service (or Retirement, if applicable) to a Participant who is a Key Employee as of the date of his Separation from Service (or Retirement, if applicable) shall not be made before the date which is six months after the Separation from Service (or Retirement, if applicable). If payments to a
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Key Employee are delayed in accordance with this Section 9.6, the payments to which the Key Employee would otherwise have been entitled during the six month period shall be accumulated and paid in a single lump sum at the time specified in Section 6.01(a) of the Adoption Agreement after the six month period elapses.
(a)A Participant is treated as a Key Employee if (i) he is employed by a Related Employer any of whose stock is publicly traded on an established securities market, and (ii) he satisfies the requirements of Code Section 416(i)(1)(A)(i), (ii) or (iii), determined without regard to Code Section 416(i)(5), at any time during the twelve month period ending on the Identification Date.
(b)A Participant who is a Key Employee on an Identification Date shall be treated as a Key Employee for purposes of the six month delay in distributions for the twelve month period beginning on the first day of a month no later than the fourth month following the Identification Date. The Identification Date and the effective date of the delay in distributions shall be determined in accordance with Section 1.06 of the Adoption Agreement.
(c)The Plan Sponsor may elect to apply an alternative method to identify Participants who will be treated as Key Employees for purposes of the six month delay in distributions if the method satisfies each of the following requirements. The alternative method is reasonably designed to include all Key Employees, is an objectively determinable standard providing no direct or indirect election to any Participant regarding its application, and results in either all Key Employees or no more than 200 Key Employees being identified in the class as of any date. Use of an alternative method that satisfies the requirements of this Section 9.6(c) will not be treated as a change in the time and form of payment for purposes of Reg. Sec. 1.409A‑2(b).
(d)The six month delay does not apply to payments described in Section 9.9(a),(b) or (d) or to payments that occur after the death of the Participant. If the payment of all or any portion of the Participant’s vested Account is being delayed in accordance with this Section 9.6 at the time he incurs a Disability which would otherwise require a distribution under the terms of the Plan, no amount shall be paid until the expiration of the six month period of delay required by this Section 9.6.
9.7      Change in Control. If the Plan Sponsor has elected to permit distributions upon a Change in Control, the following provisions shall apply. A distribution made upon a Change in Control will be made at the
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time specified in Section 6.01(a) of the Adoption Agreement in the form elected by the Participant in accordance with the procedures described in Article 4. Alternatively, if the Plan Sponsor has elected in accordance with Section 11.02 of the Adoption Agreement to require distributions upon a Change in Control, the Participant’s remaining vested Account shall be paid to the Participant or the Participant’s Beneficiary at the time specified in Section 6.01(a) of the Adoption Agreement as a single lump sum payment. All distributions made in accordance with this Section 9.7 are subject to the provisions of Section 9.6.
If a Participant continues to make deferrals in accordance with Article 4 after he has received a distribution due to a Change in Control, the residual amount payable to the Participant shall be paid at the time and in the form specified in the elections he makes in accordance with Article 4 or upon his death or Disability as provided in Article 8.
Whether a Change in Control has occurred will be determined by the Administrator. A distribution to the Participant will be treated as occurring upon a Change in Control if the Plan Sponsor terminates the Plan in accordance with Section 10.2 and distributes the Participant’s benefits within twelve months of a Change in Control as provided in Section 10.3.
9.8      Permissible Delays in Payment. Distributions may be delayed beyond the date payment would otherwise occur in accordance with the provisions of Articles 8 and 9 in any of the following circumstances as long as the Employer treats all payments to similarly situated Participants on a reasonably consistent basis.
(a)      The Employer may delay payment if it reasonably anticipates that its deduction with respect to such payment would be limited or eliminated by the application of Code Section 162(m). Payment must be made during the Participant’s first taxable year in which the Employer reasonably anticipates, or should reasonably anticipate, that if the payment is made during such year the deduction of such payment will not be barred by the application of Code Section 162(m) or during the period beginning with the Participant’s Separation from Service and ending on the later of the last day of the Employer’s taxable year in which the Participant separates from service or the 15th day of the third month following the Participant’s Separation from Service. If a scheduled payment to a Participant is delayed in accordance with this Section 9.8(a), all scheduled payments to the Participant that could be delayed in accordance with this Section 9.8(a) will also be delayed.
(b)      The Employer may also delay payment if it reasonably anticipates that the making of the payment will violate federal securities laws or
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other applicable laws provided payment is made at the earliest date on which the Employer reasonably anticipates that the making of the payment will not cause such violation.
(c)      The Employer reserves the right to amend the Plan to provide for a delay in payment upon such other events and conditions as the Secretary of the Treasury may prescribe in generally applicable guidance published in the Internal Revenue Bulletin.
9.9      Permitted Acceleration of Payment. The Employer may permit acceleration of the time or schedule of any payment or amount scheduled to be paid pursuant to a payment under the Plan provided such acceleration would be permitted by the provisions of Reg. Sec. 1.409A‑3(j)(4), including the following events:
(a)      Domestic Relations Order. A payment may be accelerated if such payment is made to an alternate payee pursuant to and following the receipt and qualification of a domestic relations order as defined in Code Section 414(p).
(b)      Compliance with Ethics Agreements and Legal Requirements. A payment may be accelerated as may be necessary to comply with ethics agreements with the Federal government or as may be reasonably necessary to avoid the violation of Federal, state, local or foreign ethics law or conflicts of laws, in accordance with the requirements of Code Section 409A.
(c)      De Minimis Amounts. A payment will be accelerated if (i) the amount of the payment is not greater than the applicable dollar amount under Code Section 402(g)(1)(B), (ii) at the time the payment is made the amount constitutes the Participant’s entire interest under the Plan and all other plans that are aggregated with the Plan under Reg. Sec. 1.409A‑1(c)(2).
(d)      FICA Tax. A payment may be accelerated to the extent required to pay the Federal Insurance Contributions Act tax imposed under Code Sections 3101, 3121(a) and 3121(v)(2) of the Code with respect to compensation deferred under the Plan (the “FICA Amount”). Additionally, a payment may be accelerated to pay the income tax on wages imposed under Code Section 3401 of the Code on the FICA Amount and to pay the additional income tax at source on wages attributable to the pyramiding Code Section 3401 wages and taxes. The total payment under this subsection (d) may not exceed the aggregate of the FICA Amount and the income tax withholding related to the FICA Amount.
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(e)      Section 409A Additional Tax. A payment may be accelerated if the Plan fails to meet the requirements of Code Section 409A; provided that such payment may not exceed the amount required to be included in income as a result of the failure to comply with the requirements of Code Section 409A.
(f)      Offset. A payment may be accelerated in the Employer’s discretion as satisfaction of a debt of the Participant to the Employer, where such debt is incurred in the ordinary course of the service relationship between the Participant and the Employer, the entire amount of the reduction in any of the Employer’s taxable years does not exceed $5,000, and the reduction is made at the same time and in the same amount as the debt otherwise would have been due and collected from the Participant.
(g)      Other Events. A payment may be accelerated in the Administrator’s discretion in connection with such other events and conditions as permitted by Code Section 409A.

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ARTICLE 10 — AMENDMENT AND TERMINATION
10.1    Amendment by Plan Sponsor. The Plan Sponsor reserves the right to amend the Plan (for itself and each Employer) through action of its Board of Directors. No amendment can directly or indirectly deprive any current or former Participant or Beneficiary of all or any portion of his Account which had accrued and vested prior to the amendment.
10.2    Plan Termination Following Change in Control or Corporate Dissolution. If so elected by the Plan Sponsor in 11.01 of the Adoption Agreement, the Plan Sponsor reserves the right to terminate the Plan and distribute all amounts credited to all Participant Accounts within the 30 days preceding or the twelve months following a Change in Control. For this purpose, the Plan will be treated as terminated only if all agreements, methods, programs and other arrangements sponsored by the Related Employer immediately after the Change in Control which are treated as a single plan under Reg. Sec. 1.409A- 1(c)(2) are also terminated so that all participants under the Plan and all similar arrangements are required to receive all amounts deferred under the terminated arrangements within twelve months of the date the Plan Sponsor irrevocably takes all necessary action to terminate the arrangements. In addition, the Plan Sponsor reserves the right to terminate the Plan within twelve months of a corporate dissolution taxed under Code Section 331 or with the approval of a bankruptcy court pursuant to 11 U. S. C. Section 503(b)(1)(A) provided that amounts deferred under the Plan are included in the gross incomes of Participants in the latest of (a) the calendar year in which the termination and liquidation occurs, (b) the first calendar year in which the amount is no longer subject to a substantial risk of forfeiture, or (c) the first calendar year in which payment is administratively practicable.
10.3    Other Plan Terminations. The Plan Sponsor retains the discretion to terminate the Plan if (a) all arrangements sponsored by the Plan Sponsor that would be aggregated with any terminated arrangement under Code Section 409A and Reg. Sec. 1.409A- 1(c)(2) are terminated, (b) no payments other than payments that would be payable under the terms of the arrangements if the termination had not occurred are made within twelve months of the termination of the arrangements, (c) all payments are made within twenty-four months of the date the Plan Sponsor takes all necessary action to irrevocably terminate and liquidate the arrangements, (d) the Plan Sponsor does not adopt a new arrangement that would be aggregated with any terminated arrangement under Code Section 409A and the regulations thereunder at any time within the three year period following the date of termination of the arrangement, and (e) the termination does not occur proximate to a downturn in the financial health of the Plan sponsor. The Plan Sponsor also reserves the right to amend
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the Plan to provide that termination of the Plan will occur under such conditions and events as may be prescribed by the Secretary of the Treasury in generally applicable guidance published in the Internal Revenue Bulletin.

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ARTICLE 11 – THE TRUST
11.1    Establishment of Trust. The Plan Sponsor may but is not required to establish a trust to hold amounts which the Plan Sponsor may contribute from time to time to correspond to some or all amounts credited to Participants under Section 6.2. In the event that the Plan Sponsor wishes to establish a trust to provide a source of funds for the payment of Plan benefits, any such trust shall be constructed to constitute an unfunded arrangement that does not affect the status of the Plan as an unfunded plan for purposes of Title I of ERISA and the Code. If the Plan Sponsor elects to establish a trust in accordance with Section 10.01 of the Adoption Agreement, the provisions of Sections 11.2 and 11.3 shall become operative.
11.2    Rabbi Trust. Any trust established by the Plan Sponsor shall be between the Plan Sponsor and a trustee pursuant to a separate written agreement under which assets are held, administered and managed, subject to the claims of the Plan Sponsor’s creditors in the event of the Plan Sponsor’s insolvency. The trust is intended to be treated as a rabbi trust in accordance with existing guidance of the Internal Revenue Service, and the establishment of the trust shall not cause the Participant to realize current income on amounts contributed thereto. The Plan Sponsor must notify the trustee in the event of a bankruptcy or insolvency.
11.3    Investment of Trust Funds. Any amounts contributed to the trust by the Plan Sponsor shall be invested by the trustee in accordance with the provisions of the trust and the instructions of the Administrator. Trust investments need not reflect the hypothetical investments selected by Participants under Section 7.1 for the purpose of adjusting Accounts and the earnings or investment results of the trust need not affect the hypothetical investment adjustments to Participant Accounts under the Plan.

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ARTICLE 12 — PLAN ADMINISTRATION
12.1    Powers and Responsibilities of the Administrator. The Administrator has the full power and the full responsibility to administer the Plan in all of its details, subject, however, to the applicable requirements of ERISA.
The Administrator’s powers and responsibilities include, but are not limited to, the following:
(a)      To make and enforce such rules and procedures as it deems necessary or proper for the efficient administration of the Plan;
(b)      To interpret the Plan, its interpretation thereof to be final, except as provided in Section 12.2, on all persons claiming benefits under the Plan;
(c)      To decide all questions concerning the Plan and the eligibility of any person to participate in the Plan;
(d)      To administer the claims and review procedures specified in Section 12.2;
(e)      To compute the amount of benefits which will be payable to any Participant, former Participant or Beneficiary in accordance with the provisions of the Plan;
(f)       To determine the person or persons to whom such benefits will be paid;
(g)      To authorize the payment of benefits;
(h)      To comply with the reporting and disclosure requirements of Part 1 of Subtitle B of Title I of ERISA;
(i)       To appoint such agents, counsel, accountants, and consultants as may be required to assist in administering the Plan;
(j)       By written instrument, to allocate and delegate its responsibilities, including the formation of an Administrative Committee to administer the Plan.
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12.2   Claims and Review Procedures.
(a)       Claims Procedure.
If any person believes he is being denied any rights or benefits under the Plan, such person may file a claim in writing with the Administrator. If any such claim is wholly or partially denied, the Administrator will notify such person of its decision in writing. Such notification will contain (i) specific reasons for the denial, (ii) specific reference to pertinent Plan provisions, (iii) a description of any additional material or information necessary for such person to perfect such claim and an explanation of why such material or information is necessary, and (iv) a description of the Plan’s review procedures and the time limits applicable to such procedures, including a statement of the person’s right to bring a civil action following an adverse decision on review. Such notification will be given within 90 days (45 days in the case of a claim regarding Disability) after the claim is received by the Administrator. The Administrator may extend the period for providing the notification by 90 days (30 days in the case of a claim regarding Disability) if special circumstances require an extension of time for processing the claim and if written notice of such extension and circumstance is given to such person within the initial 90 day period (45 day period in the case of a claim regarding Disability). If such notification is not given within such period, the claim will be considered denied as of the last day of such period and such person may request a review of his claim.
(b)       Review Procedure.
Within 60 days (180 days in the case of a claim regarding Disability) after the date on which a person receives a written notification of denial of claim (or, if written notification is not provided, within 60 days (180 days in the case of a claim regarding Disability) of the date denial is considered to have occurred), such person (or his duly authorized representative) may (i) file a written request with the Administrator for a review of his denied claim and of pertinent documents and (ii) submit written issues and comments to the Administrator. The Administrator will notify such person of its decision in writing. Such notification will be written in a manner calculated to be understood by such person and will contain specific reasons for the decision as well as specific references to pertinent Plan provisions. The notification will explain that the person is entitled to receive, upon request and free of charge,
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reasonable access to and copies of all pertinent documents and has the right to bring a civil action following an adverse decision on review. The decision on review will be made within 60 days (45 days in the case of a claim regarding Disability). The Administrator may extend the period for making the decision on review by 60 days (45 days in the case of a claim regarding Disability) if special circumstances require an extension of time for processing the request such as an election by the Administrator to hold a hearing, and if written notice of such extension and circumstances is given to such person within the initial 60‑day period (45 days in the case of a claim regarding Disability). If the decision on review is not made within such period, the claim will be considered denied.
(c)       Exhaustion of Claims Procedures and Right to Bring Legal Claim
No action at law or equity shall be brought more than one (1) year after the Administrator’s affirmation of a denial of a claim, or, if earlier, more than four (4) years after the facts or events giving rising to the claimant’s allegation(s) or claim(s) first occurred.
12.3    Plan Administrative Costs. All reasonable costs and expenses (including legal, accounting, and employee communication fees) incurred by the Administrator in administering the Plan shall be paid by the Plan to the extent not paid by the Employer.

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ARTICLE 13 – MISCELLANEOUS
13.1    Unsecured General Creditor of the Employer. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interests or claims in any property or assets of the Employer. For purposes of the payment of benefits under the Plan, any and all of the Employer’s assets shall be, and shall remain, the general, unpledged, unrestricted assets of the Employer. Each Employer’s obligation under the Plan shall be merely that of an unfunded and unsecured promise to pay money in the future.
13.2    Employer’s Liability. Each Employer’s liability for the payment of benefits under the Plan shall be defined only by the Plan and by the deferral agreements entered into between a Participant and the Employer. An Employer shall have no obligation or liability to a Participant under the Plan except as provided by the Plan and a deferral agreement or agreements. An Employer shall have no liability to Participants employed by other Employers.
13.3    Limitation of Rights. Neither the establishment of the Plan, nor any amendment thereof, nor the creation of any fund or account, nor the payment of any benefits, will be construed as giving to the Participant or any other person any legal or equitable right against the Employer, the Plan or the Administrator, except as provided herein; and in no event will the terms of employment or service of the Participant be modified or in any way affected hereby.
13.4    Anti-Assignment. Except as may be necessary to fulfill a domestic relations order within the meaning of Code Section 414(p), none of the benefits or rights of a Participant or any Beneficiary of a Participant shall be subject to the claim of any creditor. In particular, to the fullest extent permitted by law, all such benefits and rights shall be free from attachment, garnishment, or any other legal or equitable process available to any creditor of the Participant and his or her Beneficiary. Neither the Participant nor his or her Beneficiary shall have the right to alienate, anticipate, commute, pledge, encumber, or assign any of the payments which he or she may expect to receive, contingently or otherwise, under the Plan, except the right to designate a Beneficiary to receive death benefits provided hereunder. Notwithstanding the preceding, the benefit payable from a Participant’s Account may be reduced, at the discretion of the administrator, to satisfy any debt or liability to the Employer.
13.5    Facility of Payment. If the Administrator determines, on the basis of medical reports or other evidence satisfactory to the Administrator, that the recipient of any benefit payments under the Plan is incapable of handling his affairs by reason of minority, illness, infirmity or other incapacity, the Administrator may
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direct the Employer to disburse such payments to a person or institution designated by a court which has jurisdiction over such recipient or a person or institution otherwise having the legal authority under State law for the care and control of such recipient. The receipt by such person or institution of any such payments therefore, and any such payment to the extent thereof, shall discharge the liability of the Employer, the Plan and the Administrator for the payment of benefits hereunder to such recipient.
13.6    Notices.  Any notice or other communication to the Employer or Administrator in connection with the Plan shall be deemed delivered in writing if addressed to the Plan Sponsor at the address specified in Section 1.03 of the Adoption Agreement and if either actually delivered at said address or, in the case of a letter, 5 business days shall have elapsed after the same shall have been deposited in the United States mails, first-class postage prepaid and registered or certified.
13.7    Tax Withholding. If the Employer concludes that tax is owing with respect to any deferral or payment hereunder, the Employer shall withhold such amounts from any payments due the Participant or from amounts deferred, as permitted by law, or otherwise make appropriate arrangements with the Participant or his Beneficiary for satisfaction of such obligation. Tax, for purposes of this Section 13.7 means any federal, state, local or any other governmental income tax, employment or payroll tax, excise tax, or any other tax or assessment owing with respect to amounts deferred, any earnings thereon, and any payments made to Participants under the Plan.
13.8    Indemnification. (a) Each Indemnitee (as defined in Section 13.8(e)) shall be indemnified and held harmless by the Employer for all actions taken by him and for all failures to take action (regardless of the date of any such action or failure to take action), to the fullest extent permitted by the law of the jurisdiction in which the Employer is incorporated, against all expense, liability, and loss (including, without limitation, attorneys’ fees, judgments, fines, taxes, penalties, and amounts paid or to be paid in settlement) reasonably incurred or suffered by the Indemnitee in connection with any Proceeding (as defined in Subsection (e)). No indemnification pursuant to this Section shall be made, however, in any case where (1) the act or failure to act giving rise to the claim for indemnification is determined by a court to have constituted willful misconduct or recklessness or (2) there is a settlement to which the Employer does not consent.
(b) The right to indemnification provided in this Section shall include the right to have the expenses incurred by the Indemnitee in defending any Proceeding paid by the Employer in advance of the final disposition of the Proceeding, to the fullest extent permitted by the law of the jurisdiction in which the Employer is incorporated; provided that, if such law requires, the payment of such expenses incurred by the Indemnitee in advance of the final disposition of a Proceeding shall be made only on delivery to the Employer of
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an undertaking, by or on behalf of the Indemnitee, to repay all amounts so advanced without interest if it shall ultimately be determined that the Indemnitee is not entitled to be indemnified under this Section or otherwise.
(c) Indemnification pursuant to this Section shall continue as to an Indemnitee who has ceased to be such and shall inure to the benefit of his heirs, executors, and administrators. The Employer agrees that the undertakings made in this Section shall be binding on its successors or assigns and shall survive the termination, amendment or restatement of the Plan.
(d) The foregoing right to indemnification shall be in addition to such other rights as the Indemnitee may enjoy as a matter of law or by reason of insurance coverage of any kind and is in addition to and not in lieu of any rights to indemnification to which the Indemnitee may be entitled pursuant to the by-laws of the Employer.
(e) For the purposes of this Section, the following definitions shall apply:
(1)   "Indemnitee" shall mean each person serving as an Administrator (or any other person who is an employee, director, or officer of the Employer) who was or is a party to, or is threatened to be made a party to, or is otherwise involved in, any Proceeding, by reason of the fact that he is or was performing administrative functions under the Plan.
(2)   "Proceeding" shall mean any threatened, pending, or completed action, suit, or proceeding (including, without limitation, an action, suit, or proceeding by or in the right of the Employer), whether civil, criminal, administrative, investigative, or through arbitration.
13.9    Successors. The provisions of the Plan shall bind and inure to the benefit of the Plan Sponsor, the Employer and their successors and assigns and the Participant and the Participant’s designated Beneficiaries.
13.10  Disclaimer. It is the Plan Sponsor’s intention that the Plan comply with the requirements of Code Section 409A. Neither the Plan Sponsor nor the Employer shall have any liability to any Participant should any provision of the Plan fail to satisfy the requirements of Code Section 409A.
13.11  Governing Law. The Plan will be construed, administered and enforced according to the laws of the State specified by the Plan Sponsor in Section 12.01 of the Adoption Agreement.

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ADOPTION AGREEMENT
1.01   PREAMBLE
By the execution of this Adoption Agreement the Plan Sponsor hereby [complete (a) or (b)]	
 	 	 	
(a)	☒	adopts a new plan as of February 1, 2017 [month, day, year]	
 	 	 	
(b)	☐	amends and restates its existing plan as of                [month, day, year] which is the Amendment Restatement Date. Except as otherwise provided in Appendix A, all amounts deferred under the Plan prior to the Amendment Restatement Date shall be governed by the terms of the Plan as in effect on the day before the Amendment Restatement Date.	
 	 	 	
 	 	Original Effective Date:                        [month, day, year]	
 	 	 	
 	 	Pre-409A Grandfathering:     ☐    Yes    ☐    No	
 
1.02   PLAN
Plan Name:	Kosmos Energy Deferred Compensation Plan	
 	
Plan Year:	Calendar	 	

1.03   PLAN SPONSOR
Name:	Kosmos Energy, LLC	
Address:	8176 Park Lane, Dallas TX, 75231	
Phone # :	214-445-9600	
EIN:	75-3117910	
Fiscal Yr:	Calendar	
 	 	
Is stock of the Plan Sponsor, any Employer or any Related Employer publicly traded on an established securities market?	
 	
☒   Yes   ☐   No	
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1.04    EMPLOYER
The following entities, in addition to the Plan Sponsor, have been authorized by the Plan Sponsor to participate in and have adopted the Plan (insert “Not Applicable” if none have been authorized):
Entity	Publicly Traded on Est. Securities Market	
 	 	
 	Yes	No	 	
N/A	☐	☐	 	
 	☐	☐	 	
 	☐	☐	 	
 	☐	☐	 	
 	☐	☐	 	
 
1.05    ADMINISTRATOR
The Plan Sponsor has designated the following party or parties to be responsible for the administration of the Plan:
Name:	Kosmos Energy, LLC	
Address:	Same as above	
 	 	
Note:	The Administrator is the person or persons designated by the Plan Sponsor to be responsible for the administration of the Plan. Neither Fidelity Employer Services Company nor any other Fidelity affiliate can be the Administrator.	
 
1.06    KEY EMPLOYEE DETERMINATION DATES
The Employer has designated                   as the Identification Date for purposes of determining Key Employees.
In the absence of a designation, the Identification Date is December 31.
The Employer has designated                   as the effective date for purposes of applying the six month delay in distributions to Key Employees.
In the absence of a designation, the effective date is the first day of the fourth month following the Identification Date.
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2.01     PARTICIPATION
(a)	☒	Employees [complete (i), (ii) or (iii)]	
 	 	
 	(i)	☐	Eligible Employees are selected by the Employer.	
 	 	 	 	
 	(ii)	☒	Eligible Employees are those employees of the Employer who satisfy the following criteria:	
 	 	 	 	
 	 	 	Senior Leadership Team members, or	
 	 	 	Senior Vice Presidents	

 	 	 	 	
 	 	 	 	
 	(iii)	☐	Employees are not eligible to participate.	
 	 	 	 	
(b)	☐	Directors [complete (i), (ii) or (iii)]	
 	 	 	 	
 	(i)	☐	All Directors are eligible to participate.	
 	 	 	 	
 	(ii)	☐	Only Directors selected by the Employer are eligible to participate.	
 	 	 	 	
 	(iii)	☒	Directors are not eligible to participate.	
 
- 3  -

 

3.01    COMPENSATION
For purposes of determining Participant contributions under Article 4 and Employer contributions under Article 5, Compensation shall be defined in the following manner [complete (a) or (b) and select (c) and/or (d), if applicable]:
(a)	☒	Compensation is defined as:	
 	 	 	
 	 	Base W-2 wages excluding LTIP	

 	 	 	

 	 	 	
 	 	 	
(b)	☐	Compensation as defined in             [insert name of qualified plan] without regard to the limitation in Section 401(a)(17) of the Code for such Plan Year.	
 	 	 	
(c)	☐	Director Compensation is defined as:	

 	 	 	

(d)	☐	Compensation shall, for all Plan purposes, be limited to $           	
 	 	 	
(e)	☐	Not Applicable.	
 
- 4  -

 

3.02   BONUSES
Compensation, as defined in Section 3.01 of the Adoption Agreement, includes the following type of bonuses that will be the subject of a separate deferral election:
 	  	Will be treated as Performance	
Type	 	Based Compensation	
 	 	 	 	
 	 	Yes	No	
Annual Discretionary Performance Bonus Compensation	 	☐	☒	
 	 	☐	☐	
 	 	☐	☐	
 	 	☐	☐	
 	 	☐	☐	
 	 	 	 	
☐	Not Applicable.	
- 5  -

 

4.01     PARTICIPANT CONTRIBUTIONS
If Participant contributions are permitted, complete (a), (b), and (c). Otherwise complete (d).
(a)       Amount of Deferrals
A Participant may elect within the period specified in Section 4.01(b) of the Adoption Agreement to defer the following amounts of remuneration in excess of the limit under Section 402(g) of the Code (or Section 414(v) of the Code for any participant eligible to make a catch-up contribution under the Kosmos Energy, LLC 401(k) Plan). For each type of remuneration listed, complete “dollar amount” and / or “percentage amount”.
(i)    Compensation Other than Bonuses [do not complete if you complete (iii)]
Type of Remuneration	Dollar Amount	% Amount	Increment	 	
 	Min	Max	Min	Max	 	 	 	
(a)	Base W-2 wages	 	 	 	50	1	 	 	
(b)	 	 	 	 	 	 	 	 	
(c)	 	 	 	 	 	 	 	 	
 
Note: The increment is required to determine the permissible deferral amounts. For example, a minimum of 0% and maximum of 20% with a 5% increment would allow an individual to defer 0%, 5%, 10%, 15% or 20%.
(ii)    Bonuses [do not complete if you complete (iii)]
Type of Bonus	Dollar Amount	% Amount	Increment	 	
 	Min	Max	Min	Max	 	 	 	
(a)	Annual Discretionary Performance Bonus Compensation	 	 	 	100	1	 	 	
(b)	 	 	 	 	 	 	 	 	
(c)	 	 	 	 	 	 	 	 	
 
(iii)   Compensation [do not complete if you completed (i) and (ii)]
Dollar Amount	% Amount	Increment	
Min	Max	Min	Max	 	

- 6  -

 

(iv) Director Compensation
Type of Compensation	Dollar Amount	% Amount	Increment	 	
 	Min	Max	Min	Max	 	 	
Annual Retainer	 	 	 	 	 	 	
Meeting Fees	 	 	 	 	 	 	
Other:	 	 	 	 	 	 	
Other:	 	 	 	 	 	 	
 
(b)       Election Period
 	 	 	 	 	
(i)	Performance Based Compensation A special election period	
 	 	 	 	 	
 	☐	Does	☐	Does Not	
 	 	
 	apply to each eligible type of performance based compensation referenced in Section 3.02 of the Adoption Agreement.	
 	 	 	 	 	
 	The special election period, if applicable, will be determined by the Employer.	
 	 	
(ii)	Newly Eligible Participants	
 	 	
 	An employee who is classified or designated as an Eligible Employee during a Plan Year	
 	 	
 	☒	May	☐	May Not	
 	 	 	 	 	
 	elect to defer Compensation earned during the remainder of the Plan Year by completing a deferral agreement within the 30 day period beginning on the date he is eligible to participate in the Plan.	
 
- 7  -

 

(c)     Revocation of Deferral Agreement
A Participant’s deferral agreement	
 	
☒	Will	
☐	Will Not	
 	 	
be cancelled for the remainder of any Plan Year during which he receives a hardship distribution of elective deferrals from a qualified cash or deferred arrangement maintained by the Employer to the extent necessary to satisfy the requirements of Reg. Sec. 1.401(k)-1(d)(3). If cancellation occurs, the Participant may resume participation in accordance with Article 4 of the Plan.	
 
(d)       No Participant Contributions
 
☐	Participant contributions are not permitted under the Plan.	
 
- 8  -

 

5.01     EMPLOYER CONTRIBUTIONS
If Employer contributions are permitted, complete (a) and/or (b). Otherwise complete (c).
(a)       Matching Contributions
 	 	 	 	 	 	
(i)	Amount	
 	 	
 	For each Plan Year, the Employer shall make a Matching Contribution on behalf of each Participant who defers Compensation for the Plan Year and satisfies the requirements of Section 5.01(a)(ii) of the Adoption Agreement equal to [complete the ones that are applicable]:	
 	 	 	
 	(A)	☒	100% of the first 8% of Compensation the Participant has elected to defer for the Plan Year	
 	 	 	 	
 	(B)	☐	An amount determined by the Employer in its sole discretion	
 	 	 	 	
 	(C)	☐	Matching Contributions for each Participant shall be limited to $            and/or            % of Compensation.	
 	 	 	 	
 	(D)	☐	Other:	 	

 	 	 	 	
 	(E)	☐	Not Applicable [Proceed to Section 5.01(b)]	
 	 	
(ii)	Eligibility for Matching Contribution	
 	 	
 	A Participant who defers Compensation for the Plan Year shall receive an allocation of Matching Contributions determined in accordance with Section 5.01(a)(i) provided he satisfies the following requirements [complete the ones that are applicable]:	
 	 	
 	(A)	☐	Describe requirements:	

- 9  -

 

 	(B)	☐	Is selected by the Employer in its sole discretion to receive an allocation of Matching Contributions	
 	 	 	 	
 	(C)	☒	No requirements	
 	 	 	 	
(iii)	Time of Allocation	
 	 	
 	Matching Contributions, if made, shall be treated as allocated [select one]:	
 	 	
 	(A)	☐	As of the last day of the Plan Year	
 	 	 	 	
 	(B)	☐	At such times as the Employer shall determine in it sole discretion	
 	 	 	 	
 	(C)	☒	At the time the Compensation on account of which the Matching Contribution is being made would otherwise have been paid to the Participant	
 	 	 	 	
 	(D)	☐	Other:	

 
(b)       Other Contributions
(i)	Amount	
 	 	
 	The Employer shall make a contribution on behalf of each Participant who satisfies the requirements of Section 5.01(b)(ii) equal to [complete the ones that are applicable]:	
 	 	 	
 	(A)	☐	An amount equal to              [insert number] % of the Participant’s Compensation	
 	 	 	 	
 	(B)	☐	An amount determined by the Employer in its sole discretion	
 	 	 	 	
- 10  -

 

 	(C)	☐	Contributions for each Participant shall be limited to $            	
 	 	 	 	
 	(D)	☐	Other:	

 	 	 	 	 	
 	 	 	 	 	
 	(E)	☒	Not Applicable [Proceed to Section 6.01]	
 
(ii)	Eligibility for Other Contributions	
 	 	
 	A Participant shall receive an allocation of other Employer contributions determined in accordance with Section 5.01(b)(i) for the Plan Year if he satisfies the following requirements [complete the one that is applicable]:	
 	 	
 	(A)	☐	Describe requirements:	

 	 	 	 	 	
 	(B)	☐	Is selected by the Employer in its sole discretion to receive an allocation of other Employer contributions	
 	 	 	 	
 	(C)	☐	No requirements	
 	 	
(iii)	Time of Allocation	
 	 	
 	Employer contributions, if made, shall be treated as allocated [select one]:	
 	 	
 	(A)	☐	As of the last day of the Plan Year	
 	 	 	 	
 	(B)	☐	At such time or times as the Employer shall determine in its sole discretion	
 	 	 	 	
- 11  -

 

 	(C)	☐	Other:	

 	 	 	 	 	
 
(c)       No Employer Contributions
☐	Employer contributions are not permitted under the Plan.	
 
- 12  -

 

6.01     DISTRIBUTIONS
The timing and form of payment of distributions made from the Participant’s vested Account shall be made in accordance with the elections made in this Section 6.01 of the Adoption Agreement except when Section 9.6 of the Plan requires a six month delay for certain distributions to Key Employees of publicly traded companies.
(a)       Timing of Distributions
(i)	All distributions shall commence in accordance with the following [choose one]:	
 	 	
 	(A)	☐	As soon as administratively feasible following the distribution event but in no event later than the time prescribed by Treas. Reg. Sec. 1.409A-3(d).	
 	(B)	☒	Monthly on specified day 10th	
 	(C)	☐	Annually on specified month and day            [insert month and day]	
 	(D)	☐	Calendar quarter on specified month and day [           month of quarter (insert 1,2 or 3);              day (insert day)]	
 	 	
(ii)	The timing of distributions as determined in Section 6.01(a)(i) shall be modified by the adoption of:	
 	 	
 	(A)	☒	Event Delay – Distribution events other than those based on Specified Date or Specified Age will be treated as not having occurred for  6  months.	
 	 	 	 	
 	(B)	☐	Hold Until Next Year – Distribution events other than those based on Specified Date or Specified Age will be treated as not having occurred for twelve months from the date of the event if payment pursuant to Section 6.01(a)(i) will thereby occur in the next calendar year or on the first payment date in the next calendar year in all other cases.	
 	 	 	 	
 	(C)	☐	Immediate Processing – The timing method selected by the Plan Sponsor under Section 6.01(a)(i) shall be overridden for the following distribution events [insert events]:	

 	 	 	 	 	
 	(D)	☐	Not applicable.	
 
(b) Distribution Events
- 13  -

 

Participants may elect the following payment events and the associated form or forms of payment. If multiple events are selected, the earliest to occur will trigger payment. For installments, insert the range of available periods (e.g., 5-15) or insert the periods available (e.g., 5,7,9).
 	 	 	    	Lump	    	Installments	
 	 	 	 	Sum	 	 	
 	 	 	 	 	 	 	 	
(i)	☒	Specified Date	 	X	 	10	years	
 	 	 	 	 	 	 	 	
(ii)	☐	Specified Age	 	 	 	 	years	
 	 	 	 	 	 	 	 	
(iii)	☒	Separation from Service	 	X	 	10	years	
 	 	 	 	 	 	 	 	
(iv)	☐	Separation from Service plus 6 months	 	 	 	 	years	
 	 	 	 	 	 	 	 	
(v)	☐	Separation from Service plus          	 	 	 	 	years	
 	 	months [not to exceed           months]	 	 	 	 	 	
 	 	 	 	 	 	 	 	
(vi)	☐	Retirement	 	 	 	 	years	
 	 	 	 	 	 	 	 	
(vii)	☐	Retirement plus 6 months	 	 	 	 	years	
 	 	 	 	 	 	 	 	
(viii)	☐	Retirement plus           months [not to	 	 	 	 	years	
 	 	exceed           months]	 	 	 	 	 	
 	 	 	 	 	 	 	 	
(ix)	☐	Disability	 	 	 	 	years	
 	 	 	 	 	 	 	 	
(x)	☐	Death	 	 	 	 	years	
 	 	 	 	 	 	 	 	
(xi)	☐	Change in Control	 	 	 	 	years	
 
The minimum deferral period for Specified Date or Specified Age event shall be 3 years.
- 14  -

 

Installments may be paid [select each that applies]
☐	Monthly	
☐	Quarterly	
☒	Annually	
 
(c) Specified Date and Specified Age elections may not extend beyond age Not Applicable  [insert age or “Not Applicable” if no maximum age applies].
- 15  -

 

(d)  Payment Election Override
Payment of the remaining vested balance of the Participant’s Account will automatically occur at the time specified in Section 6.01(a) of the Adoption Agreement in the form indicated upon the earliest to occur of the following events [check each event that applies and for each event include only a single form of payment]:
 	    	EVENTS	    	 	    	FORM OF PAYMENT	
☐	 	Separation from Service	 	 	 	Lump sum	 	 	 	Installments	
☐	 	Separation from	 	 	 	 	 	 	 	 	
 	 	Service before Retirement	 	 	 	Lump sum	 	 	 	Installments	
☒	 	Death	 	X	 	Lump sum	 	 	 	Installments	
☒	 	Disability	 	X	 	Lump sum	 	 	 	Installments	
☐	 	Not Applicable	 	 	 	 	 	 	 	 	
 
(e)   Involuntary Cashouts
☐	If the Participant’s vested Account at the time of his Separation from Service does not exceed $            distribution of the vested Account shall automatically be made in the form of a single lump sum in accordance with Section 9.5 of the Plan.	
 	 	
☒	There are no involuntary cashouts.	
 
(f)  Retirement
☐	Retirement shall be defined as a Separation from Service that occurs on or after the Participant [insert description of requirements]:	

 	 	 	
 	 	 	
☒	No special definition of Retirement applies.	
 
- 16  -

 

(g) Distribution Election Change
A Participant	
 	 	
☐	Shall	
☒	Shall Not	
 	 	
be permitted to modify a scheduled distribution date and/or payment option in accordance with Section 9.2 of the Plan.	
 	 	
A Participant shall generally be permitted to elect such modification            number of times.	
 	 	
Administratively, allowable distribution events will be modified to reflect all options necessary to fulfill the distribution change election provision.	
 
(h)  Frequency of Elections
The Plan Sponsor	
 	 	
☒	Has	
☐	Has Not	
 	 	
Elected to permit annual elections of a time and form of payment for amounts deferred under the Plan. If a single election of a time and/or form of payment is required, the Participant will make such election at the time he first completes a deferral agreement which, in all cases, will be no later than the time required by Reg. Sec. 1.409A-2.	
 
- 17  -

 

7.01    VESTING
(a) Matching Contributions
The Participant’s vested interest in the amount credited to his Account attributable to Matching Contributions shall be based on the following schedule:
 	☐	Years of Service	    	Vesting %	    	 	
 	 	0	 	 	 	(insert ‘100’ if there is immediate vesting)	
 	 	1	 	 	 	 	
 	 	2	 	 	 	 	
 	 	3	 	 	 	 	
 	 	4	 	 	 	 	
 	 	5	 	 	 	 	
 	 	6	 	 	 	 	
 	 	7	 	 	 	 	
 	 	8	 	 	 	 	
 	 	9	 	 	 	 	
 	 	 	 	 	 	 	
 	☒	Other:	
 	 	3 years of Plan participation (one-time vesting event)	

 	☐	Class year vesting applies.	

 	☐	Not applicable.	
 
(b)  Other Employer Contributions
The Participant’s vested interest in the amount credited to his Account attributable to Employer contributions other than Matching Contributions shall be based on the following schedule:
 	☐	Years of Service	    	Vesting %	    	 	
 	 	0	 	 	 	(insert ‘100’ if there is immediate vesting)	
 	 	1	 	 	 	 	
 	 	2	 	 	 	 	
 	 	3	 	 	 	 	
 	 	4	 	 	 	 	
 	 	5	 	 	 	 	
- 18  -

 

 	 	6	 	 	 	 	
 	 	7	 	 	 	 	
 	 	8	 	 	 	 	
 	 	9	 	 	 	 	
 	 	 	 	 	 	 	
 	☐	Other:	

 	 	 	
 	☐	Class year vesting applies.	

 	☒	Not applicable.	
- 19  -

 

(c) Acceleration of Vesting
A Participant’s vested interest in his Account will automatically be 100% upon the occurrence of the following events: [select the ones that are applicable]:
(i)	☒	Death	
 	 	 	
(ii)	☒	Disability	
 	 	 	
(iii)	☒	Change in Control	
 	 	 	
(iv)	☐	Eligibility for Retirement	
 	 	 	
(v)	☐	Other:	
 	 	 	
(vi)	☐	Not applicable.	
 
(d)  Years of Service
(i)	 	A Participant’s Years of Service shall include all service performed for the Employer and	
 	 	 	    	 	
 	 	☐	 	Shall	
 	 	☐	 	Shall Not	
 	 	 	
 	 	include service performed for the Related Employer.	
 	 	 	
(ii)	 	Years of Service shall also include service performed for the following entities:	

 	 	 	

 	 	 	
 	 	 	
(iii)	 	Years of Service shall be determined in accordance with (select one)	
 	 	 	
- 20  -

 

 	 	(A)	☐	    	The elapsed time method in Treas. Reg. Sec. 1.410(a)-7	
 	 	 	 	 	 	
 	 	(B)	☐	 	The general method in DOL Reg. Sec. 2530.200b-1 through b-4	
 	 	 	 	 	 	
 	 	(C)	☐	 	The Participant’s Years of Service credited under [insert name of plan]	

 	 	 	 	 	 	 	
 	 	(D)	☐	 	Other:	

 	 	 	 	 	 	 	
 	 	 	 	 	 	 	
(iv)	 	☒	 	Not applicable.	
- 21  -

 

8.01 UNFORESEEABLE EMERGENCY
(a)	    	A withdrawal of Participant contributions due to an Unforeseeable Emergency as defined in Section 2.24:	
 	 	 	
 	 	☒	Will	
 	 	☐	Will Not [if Unforeseeable Emergency withdrawals are not permitted, proceed to Section 9.01]	
 	 	 	
 	 	be allowed.	
 	 	 	
(b)	 	Upon a withdrawal due to an Unforeseeable Emergency, a Participant’s deferral election for the remainder of the Plan Year:	
 	 	 	
 	 	☒	Will	
 	 	☐	Will Not	
 	 	 	
 	 	be cancelled. If cancellation occurs, the Participant may resume participation in accordance with Article 4 of the Plan.	
 
- 22  -

 

9.01 INVESTMENT DECISIONS
Investment decisions regarding the hypothetical amounts credited to a Participant’s Account shall be made by [select one]:	
 	 	 	
(a)	☒	The Participant or his Beneficiary	
 	 	 	
(b)	☐	The Employer	
 
- 23  -

 

10.01 TRUST
The Employer [select one]:	
 	 	
☒	Does	
☐	Does Not	
 
intend to establish a rabbi trust as provided in Article 11 of the Plan.
- 24  -

 

11.01 TERMINATION UPON CHANGE IN CONTROL
The Plan Sponsor	
 	 	
☒	Reserves	
☐	Does Not Reserve	
 	 	
the right to terminate the Plan and distribute all vested amounts credited to Participant Accounts upon a Change in Control as described in Section 9.7.	
 
11.02 AUTOMATIC DISTRIBUTION UPON CHANGE IN CONTROL
Distribution of the remaining vested balance of each Participant’s Account	
 	 	
☐	Shall	
☒	Shall Not	
 	 	
automatically be paid as a lump sum payment upon the occurrence of a Change in Control as provided in Section 9.7.	
 
- 25  -

 

12.01 GOVERNING STATE LAW
The laws of Texas shall apply in the administration of the Plan to the extent not preempted by ERISA.
- 26  -

 

EXECUTION PAGE
The Plan Sponsor has caused this Adoption Agreement to be executed this       1ST      day of    MAY        , 20   17         .
 	 	 	
PLAN SPONSOR:	    	/s/ Thomas P. Chambers	
 	 	 	
By:	 	THOMAS P. CHAMBERS	
 	 	 	
Title:	 	SVP / CFO	
 
- 27  -

 

APPENDIX A
SPECIAL EFFECTIVE DATES
Not Applicable
 
- 28  -

Exhibit 31.1
 
Certification of Chief Executive Officer
 
I, Andrew G. Inglis, certify that:
 
1.I have reviewed this quarterly report on Form 10-Q 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: May 8, 2017	/s/ ANDREW G. INGLIS	
 	Andrew G. Inglis	
 	Chairman of the Board of Directors and Chief Executive Officer	
 	(Principal Executive Officer)	

Exhibit 31.2
 
Certification of Chief Financial Officer
 
I, Thomas P. Chambers, certify that:
 
1.I have reviewed this quarterly report on Form 10-Q 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: May 8, 2017	/s/ THOMAS P. CHAMBERS	
 	Thomas P. Chambers	
 	Senior Vice President and Chief Financial Officer	
 	(Principal Financial Officer)	

Exhibit 32.1
 
Certification of Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
 
In connection with the accompanying quarterly report of Kosmos Energy Ltd. (the “Company”) on Form 10-Q for the quarter ended March 31, 2017, 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: May 8, 2017	/s/ ANDREW G. INGLIS	
 	Andrew G. Inglis	
 	Chairman of the Board of Directors and Chief Executive Officer	
 	(Principal Executive Officer)	
 
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2
 
Certification of Chief Financial Officer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
 
In connection with the accompanying quarterly report of Kosmos Energy Ltd. (the “Company”) on Form 10-Q for the quarter ended March 31, 2017, 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: May 8, 2017	/s/ THOMAS P. CHAMBERS	
 	Thomas P. Chambers	
 	Senior Vice President and Chief Financial Officer	
 	(Principal Financial Officer)	
 
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.