Edgar Filing: Kosmos Energy Ltd.

kos_Current folio_10Q

deriv a

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 September 30, 2016


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

For the transition period from to

Commission file number: 001-35167

Kosmos Energy Ltd.

(Exact name of registrant as specified in its charter)


Bermuda		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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☒		Accelerated filer ☐

Non-accelerated filer ☐		Smaller reporting company ☐
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

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 November 1, 2016
Common Shares, $0.01 par value		386,701,970

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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 September 30, 2016 and December 31, 2015	7
Consolidated Statements of Operations for the three and nine months ended September 30, 2016 and 2015	8
Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2016 and 2015	9
Consolidated Statements of Shareholders’ Equity for the nine months ended September 30, 2016	10
Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	11
Notes to Consolidated Financial Statements	12
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3. Quantitative and Qualitative Disclosures about Market Risk	41
Item 4. Controls and Procedures	43

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	44
Item 1A. Risk Factors	44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3. Defaults Upon Senior Securities	44
Item 4. Mine Safety Disclosures	44
Item 5. Other Information	44
Item 6. Exhibits	46
Signatures	47
Index to Exhibits	48

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.


“2D seismic data”		Two-dimensional seismic data, serving as interpretive data that allows a view of a vertical cross-section beneath a prospective area.

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

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

“ASC”		Financial Accounting Standards Board Accounting Standards Codification.

“ASU”		Financial Accounting Standards Board Accounting Standards Update.

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

“BBbl”		Billion barrels of oil.

“BBoe”		Billion barrels of oil equivalent.

“Bcf”		Billion cubic feet.

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

“Boepd”		Barrels of oil equivalent per day.

“Bopd”		Barrels of oil per day.

“Bwpd”		Barrels of water per day.

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

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

“Development”		The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.

“Dry hole”		A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.

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“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.

“MBbl”		Thousand barrels of oil.

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“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.

“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.

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“Resource Bridge”		Borrowing Base availability attributable to probable reserves and contingent resources from Jubilee Field Future Phases, Tweneboa, Enyenra and Ntomme fields and potentially Mahogany, Teak and Akasa fields.

“Shelf margin”		The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.

“Stratigraphy”		The study of the composition, relative ages and distribution of layers of sedimentary rock.

“Stratigraphic trap”		A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.

“Structural trap”		A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and 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)


	September 30,		December 31,
	2016		2015
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	109,040	$	275,004
Restricted cash		25,588		28,533
Receivables:
Joint interest billings		52,042		67,200
Oil sales		—		35,950
Other		39,833		34,882
Inventories		82,062		85,173
Prepaid expenses and other		9,602		24,766
Derivatives		68,434		182,640
Total current assets		386,601		734,148

Property and equipment:
Oil and gas properties, net		2,750,203		2,314,226
Other property, net		8,015		8,613
Property and equipment, net		2,758,218		2,322,839

Other assets:
Restricted cash		51,632		7,325
Long-term receivables - joint interest billings		45,998		37,687
Deferred financing costs, net of accumulated amortization of $10,528 and $8,475 at September 30, 2016 and December 31, 2015, respectively		5,933		7,986
Long-term deferred tax assets		32,605		33,209
Derivatives		12,493		59,856
Other		8,337		—
Total assets	$	3,301,817	$	3,203,050

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	173,972	$	295,689
Accrued liabilities		100,430		159,897
Derivatives		8,055		1,155
Total current liabilities		282,457		456,741

Long-term liabilities:
Long-term debt		1,319,094		860,878
Derivatives		17,428		4,196
Asset retirement obligations		61,163		43,938
Deferred tax liabilities		483,740		502,189
Other long-term liabilities		9,689		9,595
Total long-term liabilities		1,891,114		1,420,796

Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2016 and December 31, 2015		—		—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 395,743,005 and 393,902,643 issued at September 30, 2016 and December 31, 2015, respectively		3,957		3,939
Additional paid-in capital		1,965,596		1,933,189
Accumulated deficit		(793,710)		(564,686)
Treasury stock, at cost, 9,101,395 and 8,812,054 shares at September 30, 2016 and December 31, 2015, respectively		(47,597)		(46,929)
Total shareholders’ equity		1,128,246		1,325,513
Total liabilities and shareholders’ equity	$	3,301,817	$	3,203,050

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
Revenues and other income:
Oil and gas revenue	$	46,628	$	96,584	$	154,259	$	324,948
Gain on sale of assets		—		—		—		24,651
Other income		20,001		(1,266)		20,179		89

Total revenues and other income		66,629		95,318		174,438		349,688

Costs and expenses:
Oil and gas production		13,574		23,157		75,647		75,481
Facilities insurance modifications		5,946		—		5,946		—
Exploration expenses		66,238		18,904		126,498		132,384
General and administrative		21,914		26,692		59,672		106,538
Depletion and depreciation		17,838		35,995		66,031		110,534
Interest and other financing costs, net		11,066		9,926		30,268		29,675
Derivatives, net		(16,891)		(142,129)		33,752		(129,579)
Other expenses, net		(795)		290		13,768		5,184

Total costs and expenses		118,890		(27,165)		411,582		330,217

Income (loss) before income taxes		(52,261)		122,483		(237,144)		19,471
Income tax expense (benefit)		7,502		62,218		(10,064)		113,307

Net income (loss)	$	(59,763)	$	60,265	$	(227,080)	$	(93,836)

Net income (loss) per share:
Basic	$	(0.15)	$	0.16	$	(0.59)	$	(0.25)
Diluted	$	(0.15)	$	0.15	$	(0.59)	$	(0.25)

Weighted average number of shares used to compute net income (loss) per share:
Basic		386,026		383,924		385,130		382,603
Diluted		386,026		390,586		385,130		382,603

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Net income (loss)	$	(59,763)	$	60,265	$	(227,080)	$	(93,836)
Other comprehensive loss:
Reclassification adjustments for derivative gains included in net income (loss)		—		(378)		—		(767)
Other comprehensive loss		—		(378)		—		(767)
Comprehensive income (loss)	$	(59,763)	$	59,887	$	(227,080)	$	(94,603)

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, 2015	393,903	$	3,939	$	1,933,189	$	(564,686)	$	(46,929)	$	1,325,513
Equity-based compensation	—		—		33,687		(1,944)		—		31,743
Restricted stock awards and units	1,840		18		(18)		—		—		—
Restricted stock forfeitures	—		—		2		—		(2)		—
Purchase of treasury stock	—		—		(1,264)		—		(666)		(1,930)
Net loss	—		—		—		(227,080)		—		(227,080)
Balance as of September 30, 2016	395,743	$	3,957	$	1,965,596	$	(793,710)	$	(47,597)	$	1,128,246

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2016		2015
Operating activities
Net loss	$	(227,080)	$	(93,836)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization		73,684		118,307
Deferred income taxes		(16,821)		77,229
Unsuccessful well costs		2,609		87,379
Change in fair value of derivatives		37,179		(127,706)
Cash settlements on derivatives, net (including $146.5 million and $154.3 million on commodity hedges during 2016 and 2015)		144,522		153,065
Equity-based compensation		30,391		62,400
Gain on sale of assets		—		(24,651)
Loss on extinguishment of debt		—		165
Other		13,358		6,731
Changes in assets and liabilities:
Decrease in receivables		29,833		17,548
Increase in inventories		(12,066)		(21,059)
(Increase) decrease in prepaid expenses and other		15,164		(7,458)
Increase (decrease) in accounts payable		(122,142)		74,936
Decrease in accrued liabilities		(34,254)		(50,571)
Net cash provided by (used in) operating activities		(65,623)		272,479

Investing activities
Oil and gas assets		(506,256)		(559,342)
Other property		(1,003)		(793)
Proceeds on sale of assets		210		28,692
Restricted cash		(41,362)		(9,594)
Net cash used in investing activities		(548,411)		(541,037)

Financing activities
Borrowings under long-term debt		450,000		100,000
Payments on long-term debt		—		(200,000)
Net proceeds from issuance of senior secured notes		—		206,774
Purchase of treasury stock		(1,930)		(17,981)
Deferred financing costs		—		(9,031)
Net cash provided by financing activities		448,070		79,762

Net decrease in cash and cash equivalents		(165,964)		(188,796)
Cash and cash equivalents at beginning of period		275,004		554,831
Cash and cash equivalents at end of period	$	109,040	$	366,035

Supplemental cash flow information
Cash paid for:
Interest	$	25,540	$	39,341
Income taxes	$	6,997	$	28,744

Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable	$	8,124	$	—

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 Margin. Our assets include existing production and development projects offshore Ghana, large discoveries offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Portugal, Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and is traded under the ticker symbol KOS.

We have one reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and 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 September 30, 2016, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2016, the consolidated results of operations for the three and nine months ended September 30, 2016 and 2015, and the consolidated cash flows for the nine months ended September 30, 2016 and 2015. 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, 2015, included in our annual report on Form 10-K.

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.

Restricted Cash

In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of September 30, 2016 and December 31, 2015, we had $24.5 million and $24.4 million, respectively, in current restricted cash to meet this requirement.

In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or

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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 September 30, 2016 and December 31, 2015, we had $1.1 million and $4.1 million, respectively, of current restricted cash and $51.6 million and $7.3 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts.

Inventories

Inventories consisted of $65.0 million and $84.4 million of materials and supplies and $17.1 million and $0.8 million of hydrocarbons as of September 30, 2016 and December 31, 2015, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded a write down of zero and $15.2 million during the three and nine months ended September 30, 2016 for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows.

Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

Recent Accounting Standards

In July 2015, the FASB issued ASU 2015-11, “Inventory (Topic 330) — Simplifying the Measurement of Inventory.” ASU 2015-11 changes the measurement principle for entities that do not measure inventory using the last-in, first-out (LIFO) or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The ASU also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The standard requires prospective application upon adoption. The Company has elected to early adopt ASU 2015-11 during the first quarter of 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the second quarter using an effective date of January 1, 2016. The change in accounting for forfeitures associated with share-based payment transactions was adopted using the modified retrospective method and resulted in a $1.9 million increase to opening accumulated deficit, a $3.0 million increase to opening additional paid-in capital and a $1.1 million increase to opening long-term deferred tax assets in the consolidated balance sheets. The changes in accounting for the recognition of excess tax benefits and tax shortfalls were adopted prospectively.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230) — Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 clarifies current GAAP or provides specific guidance on eight cash flow classification issues to reduce current and potential future diversity in practice. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

In October 2016, the FASB issued ASU 2016-16, “Income Taxes (Topic 740) — Intra-Entity Transfers of Assets Other Than Inventory.” ASU 2016-16 requires the company to recognize income tax consequences, if any, on intercompany asset transfers, other than inventory, when the transfer occurs. The ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements.

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3. Acquisitions and Divestitures

In January and February 2016, we entered into farm-in agreements with Equator Exploration STP Block 5 Limited and Equator Exploration STP Block 12 Limited, affiliates of Oando Energy Resources, for Block 5 and Block 12, respectively, offshore Sao Tome and Principe, and whereby we acquired a 65% participating interest and operatorship in each block, effective as of February and March 2016, respectively. The national petroleum agency, Agencia Nacional do Petroleo de Sao Tome and Principe (“ANP STP”), has a 15% and 12.5% carried interest in Block 5 and Block 12, respectively.

In April 2016, we entered into a farm-out agreement with Hess Suriname Exploration Limited, a wholly-owned subsidiary of the Hess Corporation (“Hess”), covering the Block 42 contract area offshore Suriname. Under the terms of the agreement, Hess acquired a one-third non-operated interest in Block 42 from both Chevron Corporation (“Chevron”) and Kosmos. As part of the agreement, Hess is funding the cost of acquiring and processing a 6,500 square kilometer 3D seismic survey, subject to a maximum spend. Additionally, Hess will disproportionately fund a portion of the first exploration well in the Block 42 contract area, subject to a maximum spend, contingent upon the partnership entering the next phase of the exploration period. The new participating interests are one-third to each of Kosmos, Chevron and Hess, respectively. Kosmos remains the operator. Staatsolie Maatschappij Suriname N.V. (“Staatsolie”), Suriname’s national oil company, has the option to back into the contract with an interest of not more than 10% upon approval of a development plan.

In May 2016, Kosmos and Capricorn Exploration and Development Company Limited, a wholly owned subsidiary of Cairn Energy PLC (“Cairn”) executed a petroleum agreement with the Office National des Hydrocarbures et des Mines ("ONHYM"), the national oil company of the Kingdom of Morocco, for the Boujdour Maritime block. The Boujdour Maritime petroleum agreement largely replaces the acreage covered by the Cap Boujdour petroleum agreement which expired in March 2016. Under the terms of the petroleum agreement, Kosmos is the operator of the Boujdour Maritime block and has a 55% participating interest, Cairn has a 20% participating interest, and ONHYM holds a 25% carried interest in the block through the exploration period. The Boujdour Maritime block is currently in the initial exploration period, which is for four years from its effective date (July 18, 2016) ending in July 2020. The initial exploration period carries a 3D seismic obligation of 5,000 square kilometers. The exploration phase may be extended twice for two years each, for a total duration of eight years at our election and subject to our fulfilling specific work obligations, which includes drilling an exploration well in each of the subsequent periods. In the event of commercial success, the Company has the right to develop and produce oil and/or gas for a period of 25 years from the grant of an exploitation concession from the Government of Morocco, which may be extended for an additional period of 10 years under certain circumstances.

In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania. We have a 90% interest and are the operator. The Mauritanian national oil company, Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”), currently has a 10% carried participating interest during the exploration period. Should a commercial discovery be made, SMHPM’s 10% carried interest is extinguished and SMHPM will have an option to acquire a participating interest between 10% and 18%. SMHPM will pay its portion of development and production costs in a commercial development. Block C6 currently comprises approximately 1.1 million acres (4,300 square kilometers), with a first exploration period of four years from the effective date (October 28, 2016). The first exploration phase includes a 2,000 square kilometer 3D seismic requirement.

4. Joint Interest Billings

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

In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners that it would exercise its right for the contractor group to pay its 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues under the terms of the Deepwater Tano (“DT”) petroleum contract. As of September 30, 2016 and December 31, 2015, the joint interest billing receivables due from GNPC for the TEN development costs were $44.0 million and $35.3 million, respectively, which are classified as long-term on the consolidated balance sheets.

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5. Property and Equipment

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


	September 30,		December 31,
	2016		2015
	(In thousands)
Oil and gas properties:
Proved properties	$	1,435,068	$	1,337,215
Unproved properties		828,556		593,510
Support equipment and facilities		1,404,664		1,241,943
Total oil and gas properties		3,668,288		3,172,668
Accumulated depletion		(918,085)		(858,442)
Oil and gas properties, net		2,750,203		2,314,226

Other property		36,325		34,807
Accumulated depreciation		(28,310)		(26,194)
Other property, net		8,015		8,613

Property and equipment, net	$	2,758,218	$	2,322,839

We recorded depletion expense of $15.6 million and $33.6 million for the three months ended September 30, 2016 and 2015, respectively, and $59.6 million and $103.4 million for the nine months ended September 30, 2016 and 2015, respectively.

6. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the nine months ended September 30, 2016. The table excludes $2.6 million in costs that were capitalized and subsequently expensed during the same period.


	September 30,
	2016
	(In thousands)
Beginning balance	$	426,881
Additions to capitalized exploratory well costs pending the determination of proved reserves		301,228
Reclassification due to determination of proved reserves		—
Capitalized exploratory well costs charged to expense		—
Ending balance	$	728,109

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:



	September 30, 2016		December 31, 2015
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	366,130	$	199,486
Exploratory well costs capitalized for a period of one to two years		152,144		17,702
Exploratory well costs capitalized for a period of three to seven years		209,835		209,693
Ending balance	$	728,109	$	426,881
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		4		3

As of September 30, 2016, 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

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West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, and the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border.

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 Petroleum, the Jubilee Unit will be expanded to include the Mahogany and Teak discoveries and revenues and expenses associated with these discoveries will be at the Jubilee Unit interests. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow after approval of the GJFFDP by Ghana’s Ministry of Petroleum.

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 Petroleum, as required under the WCTP petroleum contract. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block, including the Akasa Discovery, to Tullow after approval of the GJFFDP by Ghana’s Ministry of Petroleum.

Wawa Discovery — In February 2016, we requested the Ghana Ministry of Petroleum to approve the enlargement of the areal extent of the TEN development and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN project. In April 2016, the Ghana Ministry of Petroleum 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.

Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled. Following additional evaluation, a decision regarding commerciality will be made.

7. Debt


	September 30,		December 31,
	2016		2015
	(In thousands)
Outstanding debt principal balances:
Facility	$	850,000	$	400,000
Senior Notes		525,000		525,000
Total		1,375,000		925,000
Unamortized deferred financing costs and discounts(1)		(55,906)		(64,122)
Long-term debt	$	1,319,094	$	860,878

(1)

Includes $32.1 million and $37.5 million of unamortized deferred financing costs related to the Facility and $23.8 million and $26.6 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2016 and December 31, 2015, respectively.

Facility

In March 2014, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.

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In September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was increased from the March 2016 redetermination by $40.4 million to $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields. As of September 30, 2016, borrowings under the Facility totaled $850.0 million and the undrawn availability under the Facility was $576.5 million (as of October 1, 2016, the availability is $616.9 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 September 30, 2016, we had no letters of credit issued under the Facility.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2016 (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, 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 September 30, 2016, we have $5.9 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 September 30, 2016, 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 September 30, 2016 (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. The LC Facility size remains at $75.0 million, as amended in July 2015, with additional commitments up to $50.0 million being available if the existing lender increases its commitment or if commitments from new financial institutions are added. Other amendments include increasing the margin from 0.5% to 0.8% per annum on amounts outstanding, adding a commitment fee payable quarterly in arrears at an annual rate equal to 0.65% on the available commitment amount and providing for issuance fees to be payable to the lender per new issuance of a letter of credit. As of September 30, 2016, there were 11 outstanding letters of credit totaling $70.3 million under the LC Facility. The LC Facility contains customary cross default provisions.

7.875% Senior Secured Notes due 2021

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

During April 2015, we issued an additional $225.0 million 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.

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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.

At September 30, 2016, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:


			Payments Due by Year
	Total		2016(2)		2017		2018		2019		2020		Thereafter
			(In thousands)
Principal debt repayments(1)	$	1,375,000	$	—	$	—	$	—	$	268,823	$	395,166	$	711,011

(1)

Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of September 30, 2016. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2016, there were no borrowings under the Corporate Revolver.

(2)

Represents payments for the period October 1, 2016 through December 31, 2016.

Interest and other financing costs, net

Interest and other financing costs, net incurred during the periods is comprised of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(In thousands)
Interest expense	$	23,057	$	20,031	$	65,829	$	54,687
Amortization—deferred financing costs		2,551		2,554		7,653		7,773
Loss on extinguishment of debt		—		—		—		165
Capitalized interest		(15,545)		(15,152)		(49,575)		(37,146)
Deferred interest		663		129		406		1,421
Interest income		(485)		(168)		(1,319)		(508)
Other, net		825		2,532		7,274		3,283
Interest and other financing costs, net	$	11,066	$	9,926	$	30,268	$	29,675

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 September 30, 2016. Volumes are net of any offsetting derivative contracts entered into.


			Weighted Average Dated Brent Price per Bbl
			Net Deferred
			Premium
Term	Type of Contract	MBbl	Payable		Swap		Sold Put		Floor		Ceiling		Call
2016:
October — December	Purchased puts	501	$	3.41	$	—	$	—	$	85.00	$	—	$	—
October — December	Three-way collars	503		—		—		—		85.00		110.00		135.00
October — December	Swaps with puts	500		—		75.00		60.00		—		—		—
2017:
January — December	Swap with puts/calls	2,000	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00
January — December	Swap with puts	2,000		—		64.95		50.00		—		—		—
January — December	Three-way collars	3,002		2.29		—		30.00		45.00		57.50		—
January — December	Sold calls(1)	2,000		—		—		—		—		85.00		—
2018:
January — December	Three-way collars	913	$	2.37	$	—	$	45.00	$	60.00	$	75.00	$	—
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 October 2016, we entered into three-way costless collar contracts for 2.0 MMBbl from January 2018 through December 2018 with a floor price of $55.00 per barrel, and a ceiling price of $61.75 per barrel and a sold put price of $40.00 per barrel. The 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 September 30, 2016:

Weighted Average

Term

Type of Contract

Floating Rate

Notional

Swap

Sold Call

(In thousands)

October 2016 — 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 September 30, 2016 and December 31, 2015 and gain/(loss) from derivatives during the three and nine months ended September 30, 2016 and 2015, respectively:


		Estimated Fair Value
		Asset (Liability)
		September 30,		December 31,
Type of Contract	Balance Sheet Location	2016		2015
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	68,434	$	182,640
Commodity(2)	Derivatives assets—long-term		12,493		59,197
Interest rate	Derivatives assets—long-term		—		659
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current		(7,102)		—
Interest rate	Derivatives liabilities—current		(953)		(1,155)
Commodity(4)	Derivatives liabilities—long-term		(16,451)		(4,196)
Interest rate	Derivatives liabilities—long-term		(977)		—
Total derivatives not designated as hedging instruments		$	55,444	$	237,145

(1)

Includes net deferred premiums payable of $4.5 million and $6.2 million related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively.

(2)

Includes net deferred premiums payable of $3.5 million and $6.9 million related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively.

(3)

Includes net deferred premiums payable of $4.6 million and zero related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively.

(4)

Includes net deferred premiums payable of $2.3 million and zero related to commodity derivative contracts as of September 30, 2016 and December 31, 2015, respectively.


		Amount of Gain/(Loss)				Amount of Gain/(Loss)
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
Type of Contract	Location of Gain/(Loss)	2016		2015		2016		2015
		(In thousands)
Derivatives in cash flow hedging relationships:
Interest rate(1)	Interest expense	$	—	$	378	$	—	$	767
Total derivatives in cash flow hedging relationships		$	—	$	378	$	—	$	767
Derivatives not designated as hedging instruments:
Commodity(2)	Oil and gas revenue	$	344	$	(1,033)	$	(712)	$	(736)
Commodity	Derivatives, net		16,891		142,129		(33,752)		129,579
Interest rate	Interest expense		760		(2,162)		(2,715)		(1,903)
Total derivatives not designated as hedging instruments		$	17,995	$	138,934	$	(37,179)	$	126,940

(1)

Amounts were reclassified from accumulated other comprehensive income or loss (“AOCI”) into earnings upon settlement during 2015.

(2)

Amounts represent the change in fair value of our provisional oil sales contracts.

Offsetting of Derivative Assets and Derivative Liabilities

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 2016 and December 31, 2015, there was not an

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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 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 September 30, 2016 and December 31, 2015, for each fair value hierarchy level:


	Fair Value Measurements Using:
	Quoted Prices in
	Active Markets for		Significant Other		Significant
	Identical Assets		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Total
	(In thousands)
September 30, 2016
Assets:
Commodity derivatives	$	—	$	80,927	$	—	$	80,927
Interest rate derivatives		—		—		—		—
Liabilities:
Commodity derivatives		—		(23,553)		—		(23,553)
Interest rate derivatives		—		(1,930)		—		(1,930)
Total	$	—	$	55,444	$	—	$	55,444
December 31, 2015
Assets:
Commodity derivatives	$	—	$	241,837	$	—	$	241,837
Interest rate derivatives		—		659		—		659
Liabilities:
Commodity derivatives		—		(4,196)		—		(4,196)
Interest rate derivatives		—		(1,155)		—		(1,155)
Total	$	—	$	237,145	$	—	$	237,145

The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.

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Commodity Derivatives

Our commodity derivatives represent crude oil three-way collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 8 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.

Provisional Oil Sales

The value attributable to the provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date.

Interest Rate Derivatives

The Company enters 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 September 30, 2016 and December 31, 2015:


	September 30, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	502,802	$	509,250	$	500,186	$	423,612
Facility		850,000		850,000		400,000		400,000
Total	$	1,352,802	$	1,359,250	$	900,186	$	823,612

The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

10. Equity-based Compensation

Restricted Stock Awards and Restricted Stock Units

The Company adopted ASU 2016-09, “Improvements to Employee Share-based Payment Accounting” during the second quarter of 2016 using an effective date of January 1, 2016. Prior period compensation expense disclosed below includes estimated forfeitures and has not been adjusted.

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.2 million and $13.9 million during the three months ended September 30, 2016 and 2015, respectively, and $30.4 million and $62.4 million for the nine months ended September 30, 2016 and 2015, respectively. The total tax benefit for the three months ended September 30, 2016 and 2015 was $3.0 million and $4.7 million,

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respectively, and $9.9 million and $21.1 million for the nine months ended September 30, 2016 and 2015, respectively. Additionally, we expensed a tax shortfall related to equity-based compensation of $1.0 million and $0.1 million for the three months ended September 30, 2016 and 2015 respectively, and $5.3 million and $18.5 million for the nine months ended September 30, 2016 and 2015, respectively. The fair value of awards vested during the three months ended September 30, 2016 and 2015 was approximately $2.4 million and $1.0 million, respectively, and $13.4 million and $51.8 million for the nine months ended September 30, 2016 and 2015, respectively. The Company has 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 criteria under the LTIP. Substantially all these awards vest over either 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.

The following table reflects the outstanding restricted stock awards as of September 30, 2016:


		Weighted-		Market / Service	Weighted-
	Service Vesting	Average		Vesting	Average
	Restricted Stock	Grant-Date		Restricted Stock	Grant-Date
	Awards	Fair Value		Awards	Fair Value
	(In thousands)			(In thousands)
Outstanding at December 31, 2015	810	$	9.20	261	$	9.44
Granted	—		—	—		—
Forfeited	—		—	(162)		9.44
Vested	(322)		9.77	(99)		9.44
Outstanding at September 30, 2016	488		8.83	—		—

The following table reflects the outstanding restricted stock units as of September 30, 2016:


		Weighted-		Market / Service	Weighted-
	Service Vesting	Average		Vesting	Average
	Restricted Stock	Grant-Date		Restricted Stock	Grant-Date
	Units	Fair Value		Units	Fair Value
	(In thousands)			(In thousands)
Outstanding at December 31, 2015	3,592	$	9.79	6,578	$	14.24
Granted	2,152		4.05	1,379		4.88
Forfeited	(131)		8.91	(70)		14.49
Vested	(1,378)		9.67	(652)		15.81
Outstanding at September 30, 2016	4,235		6.94	7,235		12.31

As of September 30, 2016, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $41.0 million over a weighted average period of 1.47 years. At September 30, 2016, the Company had approximately 8.3 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 of these awards ranged from $6.70 to $13.57 per award for restricted stock awards and $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 41.3% to 56.7% for the restricted stock awards and 44.0% to 54.0% for restricted stock units. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.5% to 1.1% for restricted stock awards and 0.5% to 1.2% for restricted stock units.

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11. Income Taxes

Income tax expense (benefit) was $7.5 million and $62.2 million for the three months ended September 30, 2016 and 2015, respectively, and $(10.1) million and $113.3 million for the nine months ended September 30, 2016 and 2015, 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 experienced losses in those countries and have a full valuation allowance reserved against the corresponding net deferred tax assets.

Income (loss) before income taxes is composed of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(In thousands)
Bermuda	$	(15,989)	$	(16,268)	$	(47,212)	$	(47,304)
United States		1,132		2,903		5,447		11,457
Foreign—other		(37,404)		135,848		(195,379)		55,318
Income (loss) before income taxes	$	(52,261)	$	122,483	$	(237,144)	$	19,471

Our effective tax rate for the three months ended September 30, 2016 and 2015 is 14% and 51%, respectively. For the nine months ended September 30, 2016 and 2015, our effective tax rate is a tax benefit of 4% and tax expense of 582%, respectively. The effective tax rate for the United States is approximately 156% and 44% for the three months ended September 30, 2016 and 2015, respectively, and 152% and 202% for the nine months ended, September 30, 2016 and 2015, respectively. The effective tax rate in the United States is impacted by the effect of equity-based compensation tax shortfalls equal to the excess tax benefit recognized for financial statement purposes over the tax benefit realized for tax return purposes. The effective tax rate for Ghana is approximately 45% and 35% for the three months ended September 30, 2016 and 2015, respectively, and a tax benefit of 27% and tax expense of 35% for the nine months ended, September 30, 2016 and 2015, respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax.

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 2015 and to Texas margin tax examinations for the tax years 2011 through 2015. In addition, the Company is open to income tax examinations for years 2011 through 2015 in its significant other foreign jurisdictions, primarily Ghana.

As of September 30, 2016, the Company had no material uncertain tax positions. The Company’s policy is to recognize interest and penalties related to income tax matters in income tax expense.

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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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands, except per share data)
Numerator:
Net income (loss)	$	(59,763)	$	60,265	$	(227,080)	$	(93,836)
Basic income allocable to participating securities(1)		—		(131)		—		—
Basic net income (loss) allocable to common shareholders		(59,763)		60,134		(227,080)		(93,836)
Diluted adjustments to income allocable to participating securities(1)		—		—		—		—
Diluted net income (loss) allocable to common shareholders	$	(59,763)	$	60,134	$	(227,080)	$	(93,836)
Denominator:
Weighted average number of shares outstanding:
Basic		386,026		383,924		385,130		382,603
Restricted stock awards and units(1)(2)		—		6,662		—		—
Diluted		386,026		390,586		385,130		382,603
Net income (loss) per share:
Basic	$	(0.15)	$	0.16	$	(0.59)	$	(0.25)
Diluted	$	(0.15)	$	0.15	$	(0.59)	$	(0.25)

(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 12.0 million and 1.8 million for the three months ended September 30, 2016 and 2015, respectively, and $12.0 million and $11.5 million for the nine months ended September 30, 2016 and 2015, respectively, from the computations of diluted net income per share because the effect would have been anti-dilutive.

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.

As of September 30, 2016, we had a commitment to drill one exploration well in Morocco and two exploration wells in Mauritania. In Morocco, our partner is obligated to fund our share of the cost of the exploration well, subject to a maximum spend of $120.0 million. Additionally, in Sao Tome and Principe we have 2D and 3D seismic requirements of 1,200 square kilometers and 4,000 square kilometers, respectively, and we have 3D seismic requirements in Mauritania and Western Sahara of 1,000 square kilometers and 5,000 square kilometers, respectively. In October 2016, we entered into a new petroleum contract for Block C6 in Mauritania which includes a 3D seismic requirement of 2,000 square kilometers.

In June 2013, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., signed a long-term rig agreement with a subsidiary of Atwood Oceanics, Inc. for the new build 6th generation drillship “Atwood Achiever.” KEV took delivery of the Atwood Achiever in September 2014. The rig agreement originally covered an initial period of three years at a day rate of approximately $0.6 million, with an option to extend the agreement for an additional three year term. In September 2015, KEV amended the rig agreement effective October 1, 2015 to extend the contract end date by one year and reduce the rate to approximately $0.5 million per day. KEV has the option to revert to the original

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day rate of approximately $0.6 million per day and original agreement end date of November 2017. If KEV exercises the option, KEV would be required to make a rate recovery payment equal to the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the option is exercised plus certain administrative and tax costs.

In November 2015, we entered into a line of credit agreement with one of our block partners, whereby our partner may draw up to $30 million on the line of credit to pay their portion of costs under the petroleum agreement. Interest accrues on drawn balances at 7.875%. The agreement matures on December 31, 2017, or earlier if certain conditions are met. As of September 30, 2016, there was $8.3 million outstanding under the agreement, which is included in other long-term assets.

Future minimum rental commitments under our leases at September 30, 2016, are as follows:


	Payments Due By Year(1)
	Total		2016(2)		2017		2018		2019		2020		Thereafter
	(In thousands)
Operating leases(3)	$	12,096	$	925	$	4,190	$	3,820	$	3,161	$	—	$	—
Atwood Achiever drilling rig contract(4)		373,181		38,957		177,624		156,600		—		—		—

(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 and seismic obligations, in our petroleum contracts.

(2)

Represents payments for the period from October 1, 2016 through December 31, 2016.

(3)

Primarily relates to corporate office and foreign office leases.

(4)

Commitments calculated using the amended day rate of $0.5 million effective October 1, 2015, excluding applicable taxes.

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14. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:


	September 30,		December 31,
	2016		2015
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	66,606	$	111,064
General and administrative expenses		20,642		24,839
Interest		6,891		17,512
Income taxes		3,188		3,418
Taxes other than income		2,485		3,064
Other		618		—
	$	100,430	$	159,897

Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations:


	September 30,
	2016
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	43,938
Liabilities incurred during period		13,463
Revisions in estimated retirement obligations		—
Accretion expense		3,762
Ending asset retirement obligations	$	61,163

The TEN Field commenced production during the quarter and an asset retirement obligation was recorded for the facilities and wells online as of September 30, 2016. Additional asset retirement obligations will be recorded in the period in which additional wells within our producing fields are commissioned.

Other Income

Other income consisted of $20.0 million of Loss of Production Income (“LOPI”) proceeds for the three and nine months ended September 30, 2016.

Facilities Insurance Modifications

Facilities insurance modifications consists of costs associated with the long-term solution to the turret bearing issue which we expect to be mitigated through proceeds received from our insurance policy. Insurance reimbursement of these costs, if any, will also be recorded to this line.

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Other Expenses, Net

Other expenses, net incurred during the period is comprised of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
	(In thousands)
Inventory write-off		—		—		15,177		—
(Gain) loss on insurance settlements		(3,047)		—		(4,003)		4,151
Other, net		2,252		290		2,594		1,033
Other expenses, net	$	(795)	$	290	$	13,768	$	5,184

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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, 2015, 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 Margin. Our assets include existing production and development projects offshore Ghana, large discoveries offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Portugal, Sao Tome and Principe, Suriname, Morocco and Western Sahara.

Recent Developments

Corporate

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 option. The first phase of this work is underway and involves locking the main bearing and the installation of a stern anchoring system to replace the three heading control tugs currently in the field. This workscope is on track to be completed by the end of 2016 and will require short periods of reduced production. The partners then plan a second phase of work to allow the FPSO to be rotated to its optimal spread moor heading, subject to government review. These phases of work are expected to cost up to $36 million net to Kosmos and it is estimated that the Jubilee FPSO will need to be shut down for 8-12 weeks during the first half of 2017.

Upon completion of the spread mooring work program, production is expected to return to the levels achieved before the turret bearing issue occurred. The partners will review potential opportunities to improve the efficiency of offtake procedures, which may include the use of a second DP shuttle tanker. The additional operating expenditure is expected to be around $28 million net to Kosmos for 2016 and $25 million net for 2017.

A deepwater CALM buoy, anticipated to be installed in the first half of 2018, is intended to restore full offloading functionality and remove the need for the DP shuttle and storage tankers and associated operating costs. Market inquiries are currently ongoing to estimate the cost and schedule for the fabrication and installation of this buoy.

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Kosmos anticipates that the financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing will be mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the partnership, 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.

Tweneboa, Enyenra and Ntomme (“TEN”)

The TEN project achieved first oil on August 17, 2016. A gradual ramp up in oil production towards the TEN FPSO capacity is anticipated around the end of 2016 as the facilities undergo performance testing and well production levels are increased to optimal rates. Additional drilling is not expected to occur at TEN until after the resolution of the Côte d’Ivoire and Ghana border dispute by the International Tribunal for the Law of the Sea tribunal whose decision is expected by late 2017.

Mauritania

In September 2016, we began a multi-block 3D seismic survey offshore Mauritania covering approximately 5,500 square kilometers over Blocks C8 and C13.

In October 2016, we entered into a petroleum contract covering Block C6 with the Islamic Republic of Mauritania. We have a 90% interest and are the operator. The Mauritanian national oil company, Societe Mauritanienne des Hydrocarbures et de Patrimoine Minier (“SMHPM”), currently has a 10% carried participating interest during the exploration period. Should a commercial discovery be made, SMHPM’s 10% carried interest is extinguished and SMHPM will have an option to acquire a participating interest between 10% and 18%. SMHPM will pay its portion of development and production costs in a commercial development. Block C6 currently comprises approximately 1.1 million acres (4,300 square kilometers), with a first exploration period of four years from the effective date (October 28, 2016. The first exploration phase includes a 2,000 square kilometer 3D seismic requirement.

Mauritania and Senegal Farm-out

We are engaged in discussions concerning the potential farm-out of a portion of our interests held under our Mauritania and Senegal petroleum contracts.

Sao Tome and Principe

Recently, Kosmos reached an agreement with a subsidiary of Galp Energia SGPS S.A. (“Galp”) to farm-out a twenty percent non-operated stake of the Company’s interest in Blocks 5, 11, and 12 offshore Sao Tome and Principe. Based on the terms of the agreement, Galp will pay a proportionate share of Kosmos’ past costs in the form of a partial carry on the 3D seismic survey expected to begin in the first quarter of 2017. The transaction is expected to close prior to year end, subject to government approval and other customary closing conditions.

Suriname

In October 2016, we began a 3D seismic survey of approximately 6,500 square kilometers over Block 42 and Block 45 offshore Suriname.

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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 and nine months ended September 30, 2016 and 2015 are included in the following table:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(In thousands, except per barrel data)
Sales volumes:
MBbl		947		1,850		3,791		5,695

Revenues:
Oil sales	$	46,628	$	96,584	$	154,259	$	324,948
Average sales price per Bbl		49.24		52.21		40.69		57.06

Costs:
Oil production, excluding workovers	$	13,525	$	23,745	$	75,587	$	62,482
Oil production, workovers		49		(588)		60		12,999
Total oil production costs	$	13,574	$	23,157	$	75,647	$	75,481

Depletion and depreciation	$	17,838	$	35,995	$	66,031	$	110,534

Average cost per Bbl:
Oil production, excluding workovers	$	14.28	$	12.84	$	19.94	$	10.97
Oil production, workovers		0.05		(0.32)		0.02		2.28
Total oil production costs		14.33		12.52		19.96		13.25

Depletion and depreciation		18.84		19.46		17.42		19.41
Oil production cost and depletion costs	$	33.17	$	31.98	$	37.38	$	32.66

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 September 30, 2016:


	Actively Drilling or				Wells Suspended or
	Completing				Waiting on Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
Jubilee Unit	—	—	—	—	—	—	2	0.48
West Cape Three Points	—	—	—	—	9	2.78	—	—
TEN	—	—	1	0.17	—	—	5	0.85
Deepwater Tano	—	—	—	—	1	0.18	—	—
Mauritania
C8 (1)	—	—	—	—	3	2.70	—	—
Senegal
Saint Louis Offshore Profond	—	—	—	—	1	0.60	—	—
Cayar Profond	—	—	—	—	1	0.60	—	—
Total	—	—	1	0.17	15	6.86	7	1.33

(1)

Chevron has withdrawn from our Mauritania blocks. Chevron’s 30% non-operated participating interest has been reassigned to us, and our participating interests in the Block C8, C12 and C13 petroleum contracts is 90%.

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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 September 30, 2016 compared to three months ended September 30, 2015


	Three Months Ended
	September 30,				Increase
	2016		2015		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	46,628	$	96,584	$	(49,956)
Gain on sale of assets		—		—		—
Other income		20,001		(1,266)		21,267
Total revenues and other income		66,629		95,318		(28,689)
Costs and expenses:
Oil and gas production		13,574		23,157		(9,583)
Facilities insurance modifications		5,946		—		5,946
Exploration expenses		66,238		18,904		47,334
General and administrative		21,914		26,692		(4,778)
Depletion and depreciation		17,838		35,995		(18,157)
Interest and other financing costs, net		11,066		9,926		1,140
Derivatives, net		(16,891)		(142,129)		125,238
Other expenses, net		(795)		290		(1,085)
Total costs and expenses		118,890		(27,165)		146,055
Income (loss) before income taxes		(52,261)		122,483		(174,744)
Income tax expense		7,502		62,218		(54,716)
Net income (loss)	$	(59,763)	$	60,265	$	(120,028)

Oil and gas revenue. Oil and gas revenue decreased by $50.0 million as a result of a lower realized price per barrel in 2016 and one cargo sold during the three months ended September 30, 2016 impacted by the turret bearing issue, compared to two cargos during the three months ended September 30, 2015. We lifted and sold 947 MBbl at an average realized price per barrel of $49.24 during the three months ended September 30, 2016 and 1,850 MBbl at an average realized price per barrel of $52.21 during the three months ended September 30, 2015.

Other income. Other income increased by $21.3 million primarily due to the recognition of $20 million in LOPI proceeds during the three months ended September 30, 2016 related to the reduced production from the Jubilee Field as a result of the FPSO turret bearing issue.

Oil and gas production. Oil and gas production costs decreased by $9.6 million during the three months ended September 30, 2016, as compared to the three months ended September 30, 2015 as a result of one cargo sold during the three months ended September 30, 2016, compared to two cargos during the three months ended September 30, 2016. However, the decrease is impacted by additional operating costs related to the turret bearing issue during the three months ended September 30, 2016.

Facilities insurance modifications. During the three months ended September 30, 2016, we incurred $5.9 million of facilities insurance modifications costs associated with the long-term solution to the turret bearing issue which we expect to recover from our insurance policy.

Exploration expenses. Exploration expenses increased by $47.3 million during the three months ended September 30, 2016, as compared to the three months ended September 30, 2015. The increase is primarily a result of $46.8 million of stacked rig costs associated with the Atwood Achiever in 2016.

General and administrative. General and administrative costs decreased by $4.8 million during the three months ended September 30, 2016, as compared with the three months ended September 30, 2015. The decrease is primarily a result of a decrease in non-cash stock-based compensation and effective cost control.

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Depletion and depreciation. Depletion and depreciation decreased $18.2 million during the three months ended September 30, 2016, as compared with the three months ended September 30, 2015. The decrease is primarily a result of lower depletion recognized related to the sale of only one cargo of oil during the three months ended September 30, 2016, as compared to two cargos during the three months ended September 30, 2015. In addition, the depletion rate is lower during the three months ended September 30, 2016 as a result of an increase in recognized proved reserves associated with the Jubilee Field in the fourth quarter of 2015.

Derivatives, net. During the three months ended September 30, 2016 and 2015, we recorded gains of $16.9 million and $142.1 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.

Income tax expense (benefit). The Company’s effective tax rates for the three months ended September 30, 2016 and 2015 were 14% and 51%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing which we expect to recover from insurance proceeds. Any such insurance recoveries would not be subject to income tax. Income tax expense decreased $54.7 million during the three months ended September 30, 2016, as compared with September 30, 2015, primarily as a result of lower revenue in Ghana.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015


	Nine Months Ended
	September 30,				Increase
	2016		2015		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	154,259	$	324,948	$	(170,689)
Gain on sale of assets		—		24,651		(24,651)
Other income		20,179		89		20,090
Total revenues and other income		174,438		349,688		(175,250)
Costs and expenses:
Oil and gas production		75,647		75,481		166
Facilites insurance modifications		5,946		—		5,946
Exploration expenses		126,498		132,384		(5,886)
General and administrative		59,672		106,538		(46,866)
Depletion and depreciation		66,031		110,534		(44,503)
Interest and other financing costs, net		30,268		29,675		593
Derivatives, net		33,752		(129,579)		163,331
Other expenses, net		13,768		5,184		8,584
Total costs and expenses		411,582		330,217		81,365
Income (loss) before income taxes		(237,144)		19,471		(256,615)
Income tax expense		(10,064)		113,307		(123,371)
Net loss	$	(227,080)	$	(93,836)	$	(133,244)

Oil and gas revenue. Oil and gas revenue decreased by $170.7 million as a result of four cargos sold during the nine months ended September 30, 2016, compared to six cargos during the nine months ended September 30, 2015, due to the impact of the turret bearing issue and a lower realized price per barrel in 2016. We lifted and sold 3,791 MBbl at an average realized price per barrel of $40.69 during the nine months ended September 30, 2016 and 5,695 MBbl at an average realized price per barrel of $57.06 during the nine months ended September 30, 2015.

Gain on sale of assets. During the nine months ended September 30, 2015, we closed a farm‑out agreement with Chevron. The proceeds from the sale were in excess of our book basis, resulting in a gain of $24.7 million.

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Other income. Other income increased by $20.1 million primarily due to the recognition of $20 million in LOPI proceeds during the three months ended September 30, 2016 related to the reduced production from the Jubilee Field as a result of the FPSO turret bearing issue.

Oil and gas production. Oil and gas production costs were flat during the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015. The 2016 costs were impacted by increased costs associated with the turret bearing issue while the 2015 costs were impacted by workovers in the Jubilee Field.

Facilities insurance modifications. During the nine months ended September 30, 2016, we incurred $5.9 million of facilities insurance modifications costs associated with the long-term solution to the turret bearing issue which we expect to recover from our insurance policy.

Exploration expenses. Exploration expenses decreased by $5.9 million during the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015. The decrease is primarily a result of $86.2 million of unsuccessful well costs for the Western Sahara CB-1 exploration well in 2015 offset by increases in 2016 of $63.2 million of stacked rig costs and a $14.8 million increase in seismic and geological and geophysical costs.

General and administrative. General and administrative costs decreased by $46.9 million during the nine months ended September 30, 2016, as compared with the nine months ended September 30, 2015. The decrease is primarily a result of a decrease in non-cash stock-based compensation and effective cost control.

Depletion and depreciation. Depletion and depreciation decreased $44.5 million during the nine months ended September 30, 2016, as compared with the nine months ended September 30, 2015. The decrease is primarily a result of depletion recognized related to the sale of four cargos of oil during the nine months ended September 30, 2016, as compared to six cargos during the nine months ended September 30, 2015. In addition, the depletion rate is lower during the three months ended September 30, 2016 as a result of an increase in recognized proved reserves associated with the Jubilee Field in the fourth quarter of 2015.

Derivatives, net. During the nine months ended September 30, 2016 and 2015, we recorded a loss of $33.8 million and a gain of $129.6 million, respectively, on our outstanding hedge positions. The loss and gain recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net increased by $8.6 million during the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015 primarily related to an impairment of inventory of $15.2 million offset by $4.0 million insurance proceeds related to a damaged riser during the nine months ended September 30, 2016 compared to a $4.2 million write-off related to a damaged riser during the nine months ended September 30, 2015.

Income tax expense (benefit). The Company’s effective tax rates for the nine months ended September 30, 2016 and 2015 were 4% and tax expense of 582%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. The effective tax rate in Ghana is impacted by non-deductible expenditures associated with the damage to the turret bearing which we expect to recover from insurance proceeds. Any insurance such recoveries would not be subject to income tax. Income tax expense decreased $123.4 million during the nine months ended September 30, 2016, as compared with September 30, 2015, primarily as a result of lower revenue in Ghana.

Liquidity and Capital Resources

We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margin. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt. In relation to cash flow generated from our operating activities, if we are unable to continuously export associated natural gas in large quantities, which causes potential production restraints in the Jubilee Field, then the Company’s cash flows from operations will be adversely affected. We have also experienced mechanical issues, including failures of our water injection facilities and gas compressor on the Jubilee FPSO, as well as the current

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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, the decline in oil prices experienced since 2014, if prolonged or if further deterioration of pricing occurs, could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements as well as impact the borrowing base available under the Facility or the related debt covenants. Commodity prices are volatile and future prices cannot be accurately predicted. We maintain a hedging program to partially mitigate the price volatility. Our investment decisions are based on longer-term commodity prices based on the long-term nature of our projects and development plans. Current commodity prices, our hedging program and our current liquidity position support our capital program for 2016. As such, our 2016 capital budget is based on our development plans for Ghana and our exploration and appraisal program.

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.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the nine months ended September 30, 2016 and 2015:


	Nine Months Ended
	September 30,
	2016		2015
	(In thousands)
Sources of cash and cash equivalents:
Net cash provided by (used in) activities	$	(65,623)	$	272,479
Net proceeds from issuance of senior secured notes		—		206,774
Borrowings under long-term debt		450,000		100,000
Proceeds on sale of assets		210		28,692
		384,587		607,945
Uses of cash and cash equivalents:
Oil and gas assets	$	506,256	$	559,342
Other property		1,003		793
Payments on long-term debt		—		200,000
Purchase of treasury stock		1,930		17,981
Deferred financing costs		—		9,031
Restricted cash		41,362		9,594
		550,551		796,741
Decrease in cash and cash equivalents	$	(165,964)	$	(188,796)

Net cash provided by (used in) operating activities. Net cash used in operating activities for the nine months ended September 30, 2016 was $65.6 million compared with net cash provided by operating activities for the nine months ended September 30, 2015 of $272.5 million. The decrease in cash provided by operating activities in the nine months ended September 30, 2016 when compared to the same period in 2015 is primarily a result of a decrease in results from operations driven by lower barrels sold related to the turret bearing issue and lower realized revenue per barrel sold.

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The following table presents our net debt and liquidity as of September 30, 2016:


	September 30, 2016
	(In thousands)
Cash and cash equivalents	$	109,040
Restricted cash		77,220
Senior Notes at par		525,000
Drawings under the Facility		850,000
Net debt	$	1,188,740

Availability under the Facility(1)	$	616,900
Availability under the Corporate Revolver	$	400,000
Available borrowings plus cash and cash equivalents	$	1,125,940

(1)

Based on September 30, 2016 redetermination effective October 1, 2016

Capital Expenditures and Investments

We expect to incur substantial costs as we:

fund asset integrity projects at Jubilee;

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

purchase and analyze seismic, evaluate 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 and reliable equipment and qualified personnel and our cash flows from operations. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.

2016 Capital Program

We estimate we will spend approximately $650 million of capital for the year ending December 31, 2016. Through September 30, 2016, we have spent approximately $557 million of the capital budget, which was front-end loaded in the first half of the year based on all of our drilling activity being completed by June 2016.

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. Given the status of ongoing prospect development, we suspended Kosmos operated drilling activities after the completion of the Teranga-1 exploration well offshore Senegal at the end of May 2016.

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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 September 2016, following the lender’s semi-annual redetermination, the borrowing base under our Facility was increased from the March 2016 redetermination by $40.4 million to $1.467 billion (effective October 1, 2016). The borrowing base calculation includes value related to the Jubilee and TEN fields, but can also potentially be further increased to $1.485 billion upon achievement of certain TEN operational milestones.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2016 (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 September 30, 2016, 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 September 30, 2016 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

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

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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 September 30, 2016:


	Payments Due By Year(5)
	Total		2016(6)		2017		2018		2019		2020		Thereafter
	(In thousands)
Principal debt repayments(1)	$	1,375,000	$	—	$	—	$	—	$	268,823	$	395,166	$	711,011
Interest payments on long-term debt(2)		376,152		12,197		90,633		88,434		76,702		63,431		44,755
Operating leases(3)		12,096		925		4,190		3,820		3,161		—		—
Atwood Achiever drilling rig contract(4)		373,181		38,957		177,624		156,600		—		—		—

(1)

(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)

Commitments calculated using the amended day rate of $0.5 million effective October 1, 2015, excluding applicable taxes. KEV has the option to revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. If KEV exercises the option, KEV would be required to make a rate recovery payment equal to the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the option is exercised plus certain administrative costs.

(5)

(6)

Represents payments for the period from October 1, 2016 through December 31, 2016.

We currently have a commitment to drill one exploration well in Morocco and two exploration wells in Mauritania. In Morocco, our partner is obligated to fund our share of the costs of the exploration well, subject to a maximum spend of $120.0 million. Additionally, in Sao Tome and Principe we have 2D and 3D seismic requirements of 1,200 square kilometers and 4,000 square kilometers, respectively, and we have 3D seismic requirements in Mauritania and Western Sahara of 1,000 square kilometers and 5,000 square kilometers, respectively. In October 2016, we entered into a new petroleum contract in Mauritania which carries a 3D seismic requirement of 2,000 square kilometers.

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


																			Liability
	October 1																		Fair Value
	Through																		at
	December 31,			Years Ending December 31,															September 30,
	2016			2017			2018			2019			2020			Thereafter			2016
				(In thousands, except percentages)
Fixed rate debt:
Senior Notes	$	—		$	—		$	—		$	—		$	—		$	525,000		$	(509,250)
Fixed interest rate		7.88	%		7.88	%		7.88	%		7.88	%		7.88	%		7.88	%
Variable rate debt:
Facility(1)	$	—		$	—		$	—		$	268,823		$	395,166		$	186,011		$	(850,000)
Weighted average interest rate(2)		3.80	%		4.00	%		4.52	%		4.75	%		5.32	%		5.82	%
Capped interest rate swaps:
Notional debt amount	$	200,000		$	200,000		$	200,000		$	—		$	—		$	—		$	(1,930)
Cap		3.00	%		3.00	%		3.00	%		—			—			—
Average fixed rate payable(3)		1.23	%		1.23	%		1.23	%		—			—			—
Variable rate receivable(4)		0.56	%		0.75	%		0.89	%		—			—			—

(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 September 30, 2016. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2016, there were no borrowings under the Corporate Revolver.

(2)

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

(3)

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

(4)

Based on implied forward rates in the yield curve at the reporting date.

Off-Balance Sheet Arrangements

As of September 30, 2016, our material off-balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with 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. These policies 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, 2015.

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-

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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;

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

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

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

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

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

the ability to obtain 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, technical, drilling, production and processing problems;

the failure of machinery and equipment necessary for the reliable production of oil and natural gas;

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.

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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.

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 9 — Derivative Financial Instruments and Note 10 — 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 nine months ended September 30, 2016:


	Derivative Contracts Assets (Liabilities)
	Commodities		Interest Rates		Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2015	$	237,641	$	(496)	$	237,145
Changes in contract fair value		(34,464)		(2,715)		(37,179)
Contract maturities		(145,803)		1,281		(144,522)
Fair value of contracts outstanding as of September 30, 2016	$	57,374	$	(1,930)	$	55,444

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 nine months ended September 30, 2016 ranged between $25.99 and $50.72.

Commodity Derivative Instruments

We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of three-way collars, put options, call options and swaps. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.

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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 September 30, 2016. Volumes are net of any offsetting derivatives entered into.


			Weighted Average Dated Brent Price per Bbl												Asset (Liability)
			Deferred												Fair Value at
			Premium												September 30,
Term	Type of Contract	MBbl	Payable		Swap		Sold Put		Floor		Ceiling		Call		2016(2)
2016:
October — December	Purchased puts	501	$	3.41	$	—	$	—	$	85.00	$	—	$	—	$	16,093
October — December	Three-way collars	503		—		—		—		85.00		110.00		135.00		17,860
October — December	Swaps with puts	500		—		75.00		60.00		—		—		—		7,401
2017:
January — December	Swap with puts/calls	2,000	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00	$	21,105
January — December	Swap with puts	2,000		—		64.95		50.00		—		—		—		15,009
January — December	Three-way collars	3,002		2.29		—		30.00		45.00		57.50		—		(11,106)
January — December	Sold calls(1)	2,000		—		—		—		—		85.00		—		(450)
2018:
January — December	Three-way collars	913	$	2.37	$	—	$	45.00	$	60.00	$	75.00	$	—	$	2,116
January — December	Sold calls(1)	2,000		—		—		—		—		65.00		—		(8,176)
2019:
January — December	Sold calls(1)	913	$	—	$	—	$	—	$	—	$	80.00	$	—	$	(2,478)

(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 September 30, 2016 which by year are: 2016 — $49.42, 2017 — $52.31 2018 — $54.88 and 2019 — $56.77. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on October 31, 2016 market quotes by year are: 2016 — $48.16, 2017 — $50.92, 2018 — $53.82 and 2019 — $55.72.

At September 30, 2016, our open commodity derivative instruments were in a net asset position of $57.4 million. As of September 30, 2016, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $39.7 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $32.5 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 September 30, 2016, we had indebtedness outstanding under the Facility of $850.0 million, of which $650.0 million bore interest at floating rates after consideration of our fixed rate interest rate hedges. The interest rate on this indebtedness as of September 30, 2016 was approximately 3.8%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.3 million in interest expense per year on the Facility. We pay commitment fees on the $576.5 million of undrawn availability and $73.5 million of unavailable commitments under the Facility and on the $400.0 million of undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.

As of September 30, 2016, the fair market value of our interest rate swaps was a net liability of approximately $1.9 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 September 30, 2016, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

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

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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 and in the “Item 1. Legal Proceedings” section of our quarterly report on Form 10-Q for the quarter ended June 30, 2016.

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, 2015.

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 nine months ended, September 30, 2016 and the average price paid per share.


	Total Number	Average
	of Shares	Price Paid
	Purchased	per Share
	(In thousands)
January 1, 2016—January 31, 2016	79	$	5.20
February 1, 2016—February 29, 2016	14		4.32
March 1, 2016—March 31, 2016	4		4.92
April 1, 2016—April 30, 2016	9		5.56
May 1, 2016—May 31, 2016	5		6.48
June 1, 2016—June 30, 2016	17		5.60
July 1, 2016—July 31, 2016	—		—
August 1, 2016—August 31, 2016	—		—
September 1, 2016—September 30, 2016	—		—
Total	128		5.22

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

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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 September 30, 2016. 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 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 September 30, 2016, as the case may be, additional reportable transactions may be disclosed by such companies.

As of September 30, 2016, funds affiliated with Warburg Pincus (“Warburg Pincus”) held approximately 31% of our outstanding common shares. We are also a party to a shareholders agreement with Warburg Pincus pursuant to which, among other things, Warburg Pincus currently has the right to designate three members of our board of directors. Accordingly, Warburg Pincus may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended September 30, 2016.

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 September 30, 2016

“Santander UK plc (“Santander UK”) holds two savings accounts and one current account for two customers resident in the United Kingdom (“UK”) who are currently designated by the United States (“US”) under the Specially Designated Global Terrorist (“SDGT”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

Santander UK held a savings account for a customer resident in the UK who is currently designated by the US under the SDGT sanctions program. The savings account was closed on July 26, 2016. Revenue generated by Santander UK on this account in the nine months ended September 30, 2016 was negligible relative to the overall revenues 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 nine months ended September 30, 2016. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

Santander UK holds three current accounts and a savings account for two customers resident in the UK who are currently designated by the US under the Transnational Criminal Organizations (“TCO”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

In addition, during the nine months ended September 30, 2016, Santander UK had an Office of Foreign Asset Control (“OFAC”) match on a power of attorney account. A party listed on the account is currently designated by the US under the Specially Designated Global Terrorist (“SDGT”) sanctions program and the Iranian Financial Sanctions Regulations. The power of attorney was removed from the account on July 29, 2016. During the nine months ended

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September 30, 2016, related revenues and profits generated by Santander UK were negligible relative to the overall revenues and profits of Banco Santander SA.”

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

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	November 7, 2016	/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*		Petroleum Agreement Regarding the Exploration for an Exploitation of Hydrocarbons between Office National Des Hydrocarbures Et Des Mines acting on behalf of the State and Kosmos Energy Maroc Mer Profonde and Capricorn Exploration and Development Company Limited in the area of interest named “Boujdour Maritime” dated May 25, 2016

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.