Kosmos Energy Ltd. - Quarter Report: 2017 September (Form 10-Q)

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, 2017



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

For the transition period from to

Commission file number: 001-35167

Kosmos Energy Ltd.

(Exact name of registrant as specified in its charter)



Bermuda		98-0686001
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)



Clarendon House
2 Church Street
Hamilton, Bermuda		HM 11
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: +1 441 295 5950

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer ☒		Accelerated filer ☐

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.



Class		Outstanding at November 1, 2017
Common Shares, $0.01 par value		389,355,364

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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	7
Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	7
Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016	8
Consolidated Statements of Shareholders’ Equity for the nine months ended September 30, 2017	9
Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016	10
Notes to Consolidated Financial Statements	11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3. Quantitative and Qualitative Disclosures about Market Risk	40
Item 4. Controls and Procedures	42

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3. Defaults Upon Senior Securities	43
Item 4. Mine Safety Disclosures	43
Item 5. Other Information	44
Item 6. Exhibits	44
Signatures	45
Index to Exhibits	46

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

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



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

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

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

“ASC”	Financial Accounting Standards Board Accounting Standards Codification.

“ASU”	Financial Accounting Standards Board Accounting Standards Update.

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

“BBbl”	Billion barrels of oil.

“BBoe”	Billion barrels of oil equivalent.

“Bcf”	Billion cubic feet.

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

“Boepd”	Barrels of oil equivalent per day.

“Bopd”	Barrels of oil per day.

“Bwpd”	Barrels of water per day.

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

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

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

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

“EBITDAX”	Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity-based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.

“E&P”	Exploration and production.

“FASB”	Financial Accounting Standards Board.

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

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

“Field life cover ratio”	The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana assets, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.

“FPSO”	Floating production, storage and offloading vessel.

“Interest cover ratio”	The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.

“Loan life cover ratio”	The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Jubilee Field and certain other fields in Ghana, to (y) the aggregate loan amounts outstanding under the Facility less the Resource Bridge, as applicable.

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“MBbl”	Thousand barrels of oil.

“Mcf”	Thousand cubic feet of natural gas.

“Mcfpd”	Thousand cubic feet per day of natural gas.

“MMBbl”	Million barrels of oil.

“MMBoe”	Million barrels of oil equivalent.

“MMcf”	Million cubic feet of natural gas.

“MMcfd”	Million cubic feet per day of natural gas.

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

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

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

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

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

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

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

“Proved developed reserves”	Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.

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

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

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

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

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

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

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

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

“Submarine fan”	A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.

“Three-way fault trap”	A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.

“Trap”	A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.

“Undeveloped acreage”	Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	September 30, 2017			December 31, 2016
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	164,162		$	194,057
Restricted cash	55,852			24,506
Receivables:
Joint interest billings, net	75,373			63,249
Oil sales	51,726			54,195
Related party	6,446			—
Other	15,756			25,893
Inventories	74,275			74,380
Prepaid expenses and other	9,359			7,209
Derivatives	16,200			31,698
Total current assets	469,149			475,187
Property and equipment:
Oil and gas properties, net	2,251,977			2,700,889
Other property, net	6,424			8,003
Property and equipment, net	2,258,401			2,708,892
Other assets:
Equity method investment	122,664			—
Restricted cash	15,194			54,632
Long-term receivables - joint interest billings	47,525			45,663
Deferred financing costs, net of accumulated amortization of $13,267 and $11,213 at September 30, 2017 and December 31, 2016, respectively	3,194			5,248
Long-term deferred tax assets	34,546			37,827
Derivatives	2,412			3,808
Other	17,363			10,208
Total assets	$	2,970,448		$	3,341,465
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable	$	100,302		$	220,627
Accrued liabilities	173,804			129,706
Derivatives	9,016			19,692
Total current liabilities	283,122			370,025
Long-term liabilities:
Long-term debt, net	1,080,352			1,321,874
Derivatives	7,256			14,123
Asset retirement obligations	68,713			63,574
Deferred tax liabilities	511,891			482,221
Other long-term liabilities	9,871			8,449
Total long-term liabilities	1,678,083			1,890,241
Shareholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2017 and December 31, 2016	—			—
Common shares, $0.01 par value; 2,000,000,000 authorized shares; 398,545,540 and 395,859,061 issued at September 30, 2017 and December 31, 2016, respectively	3,985			3,959
Additional paid-in capital	2,004,578			1,975,247
Accumulated deficit	(951,123		)	(850,410		)
Treasury stock, at cost, 9,188,819 and 9,101,395 shares at September 30, 2017 and December 31, 2016, respectively	(48,197		)	(47,597		)
Total shareholders’ equity	1,009,243			1,081,199
Total liabilities and shareholders’ equity	$	2,970,448		$	3,341,465

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Revenues and other income:
Oil and gas revenue	$	151,240		$	46,628		$	391,035		$	154,259
Other income, net	2			20,001			58,697			20,179
Total revenues and other income	151,242			66,629			449,732			174,438
Costs and expenses:
Oil and gas production	39,187			13,574			80,677			75,647
Facilities insurance modifications, net	(3,906		)	5,946			(1,334		)	5,946
Exploration expenses	36,983			66,238			162,679			126,498
General and administrative	20,029			21,914			50,555			59,672
Depletion and depreciation	73,490			17,838			180,909			66,031
Interest and other financing costs, net	18,478			11,066			54,729			30,268
Derivatives, net	26,864			(16,891		)	(36,404		)	33,752
Other expenses, net	5,037			(795		)	14,233			13,768
Total costs and expenses	216,162			118,890			506,044			411,582
Loss before income taxes	(64,920		)	(52,261		)	(56,312		)	(237,144		)
Income tax expense (benefit)	(1,515		)	7,502			44,401			(10,064		)
Net loss	$	(63,405	)	$	(59,763	)	$	(100,713	)	$	(227,080	)

Net loss per share:
Basic	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)
Diluted	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)

Weighted average number of shares used to compute net loss per share:
Basic	389,058			386,026			388,114			385,130
Diluted	389,058			386,026			388,114			385,130

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In thousands)

(Unaudited)



				Additional
	Common Shares			Paid-in			Accumulated			Treasury
	Shares	Amount		Capital			Deficit			Stock			Total
Balance as of December 31, 2016	395,859	$	3,959	$	1,975,247		$	(850,410	)	$	(47,597	)	$	1,081,199
Equity-based compensation	—	—		30,873			—			—			30,873
Restricted stock awards and units	2,686	26		(26		)	—			—			—
Purchase of treasury stock	—	—		(1,516		)	—			(600		)	(2,116		)
Net loss	—	—		—			(100,713		)	—			(100,713		)
Balance as of September 30, 2017	398,545	$	3,985	$	2,004,578		$	(951,123	)	$	(48,197	)	$	1,009,243

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Nine Months Ended September 30,
	2017			2016
Operating activities
Net loss	$	(100,713	)	$	(227,080	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization	188,563			73,684
Deferred income taxes	32,820			(16,821		)
Unsuccessful well costs	24,515			2,609
Change in fair value of derivatives	(25,924		)	37,179
Cash settlements on derivatives, net (including $36.4 million and $146.5 million on commodity hedges during 2017 and 2016)	25,275			144,522
Equity-based compensation	29,945			30,391
Loss on equity method investment	11,230			—
Other	3,412			13,358
Changes in assets and liabilities:
Decrease in receivables	3,232			29,833
(Increase) decrease in inventories	58			(12,066		)
(Increase) decrease in prepaid expenses and other	(19,327		)	15,164
Decrease in accounts payable	(120,325		)	(122,142		)
Increase (decrease) in accrued liabilities	41,651			(34,254		)
Net cash provided by (used in) operating activities	94,412			(65,623		)
Investing activities
Oil and gas assets	(100,712		)	(506,256		)
Other property	(1,639		)	(1,003		)
Proceeds on sale of assets	222,068			210
Net cash provided by (used in) investing activities	119,717			(507,049		)
Financing activities
Borrowings under long-term debt	—			450,000
Payments on long-term debt	(250,000		)	—
Purchase of treasury stock	(2,116		)	(1,930		)
Net cash provided by (used in) financing activities	(252,116		)	448,070
Net decrease in cash, cash equivalents and restricted cash	(37,987		)	(124,602		)
Cash, cash equivalents and restricted cash at beginning of period	273,195			310,862
Cash, cash equivalents and restricted cash at end of period	$	235,208		$	186,260

Supplemental cash flow information
Cash paid for:
Interest	$	48,694		$	25,540
Income taxes	$	27,199		$	6,997
Non-cash activity:
Conversion of joint interest billings receivable to long-term note receivable	$	—		$	8,124
Contribution to equity method investment	$	133,893		$	—

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

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

Kosmos is a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara. Kosmos is listed on the New York Stock Exchange and London 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, 2017, the changes in the consolidated statements of shareholders’ equity for the nine months ended September 30, 2017, the consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and the consolidated cash flows for the nine months ended September 30, 2017 and 2016. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2016, included in our annual report on Form 10-K.

Investment in Corporate Joint Venture

Kosmos held a 50.01% interest in Kosmos BP Senegal Limited (“KBSL”), which we exercised significant influence over. Our investment in KBSL is accounted for under the equity method of accounting. In applying the equity method of accounting, our investment in KBSL was initially recorded at carryover basis of assets contributed and subsequently adjusted for the Company’s proportionate share of earnings, losses and distributions. During the three and nine month periods ended September 30, 2017 we recognized $4.8 million and $11.2 million, respectively, related to our share of losses in KBSL. As of September 30, 2017, our investment in KBSL was $122.7 million and is reported as an equity method investment in our consolidated balance sheets. We had related party receivables of $6.4 million as of September 30, 2017, which relate to amounts due from KBSL for costs incurred by Kosmos on behalf of KBSL.

In October 2017, upon approval, KBSL transferred a 30% working interest in the Cayar offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal to BP Senegal Investments Limited in exchange for their outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and will no longer be accounted for under the equity method of accounting. After the transfer, KBSL has a 30% working interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") offshore Senegal.

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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.

Cash, Cash Equivalents and Restricted Cash



	September 30, 2017		December 31, 2016
	(In thousands)
Cash and cash equivalents	$	164,162	$	194,057
Restricted cash - current	55,852		24,506
Restricted cash - long-term	15,194		54,632
Total cash, cash equivalents and restricted cash	$	235,208	$	273,195

Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.

In accordance with our commercial debt facility (the “Facility”), we are required to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.875% Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver or the Facility, whichever is greater. As of September 30, 2017 and December 31, 2016, we had $24.7 million and $24.5 million, respectively, in current restricted cash to meet this requirement.

In addition, in accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post 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, 2017 and December 31, 2016, we had $31.1 million and zero, respectively, of current restricted cash and $15.2 million and $54.6 million, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts.

Inventories

Inventories consisted of $68.9 million and $68.1 million of materials and supplies and $5.4 million and $6.3 million of hydrocarbons as of September 30, 2017 and December 31, 2016, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of nil and $15.2 million during the nine months ended September 30, 2017 and 2016, respectively, for materials and supplies inventories as other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows.

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

Recent Accounting Standards

Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB

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ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company completed its assessment of the new accounting standard and does not expect the adoption of this standard to have a material impact to our revenue recognition based on our existing contracts with customers. We will adopt the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard.

3. Acquisitions and Divestitures

In December 2016, we announced transactions with affiliates of BP p.l.c. (‘‘BP’’) in Mauritania and Senegal following a competitive farm-out process for our interests in our blocks offshore Mauritania and Senegal. The Mauritania and Senegal transactions closed in January 2017 and February 2017, respectively. In Mauritania, BP acquired a 62% participating interest in our four Mauritania licenses (C6, C8, C12 and C13). In Senegal, BP acquired a 49.99% interest in KBSL, our majority owned affiliate company which held a 60% participating interest in the Senegal Blocks. Previously we indicated that KBSL would hold a 65% participating interest upon the completion of our exercise in December 2016 of an option to increase our equity in each contract area by 5% in exchange for carrying Timis Corporation Limited’s (“Timis”) paying interest share of a third well in either contract area, subject to a maximum gross well cost of $120.0 million. However, we agreed to withdraw the exercise of this call option upon completion of an agreement between BP and Timis by which BP acquired Timis’ entire 30% participating interest in the Senegal Blocks. The transaction between BP and Timis was completed and KBSL’s participating interest in these blocks remains at 60%. In consideration for these transactions, Kosmos received $162 million in cash up front during the first quarter of 2017 and will receive a $228 million exploration and appraisal carry (increased from $221 million upon completion of the transfer of a 30% working interest to BP Senegal Investments Limited), up to $533 million in a development carry and variable consideration up to $2 per barrel for up to 1 billion barrels of liquids, structured as a production royalty, subject to future liquids discoveries and prevailing oil prices. The effective date of these transactions was July 1, 2016, with BP paying interim costs from the effective date to the closing dates. We reduced our unproved property balance by $221.9 million for the consideration received as a result of these transactions including the upfront cash and interim costs from the transaction date to the effective date.

In November 2015, we entered into a line of credit agreement with Timis, whereby Timis had the right to draw up to $30.0 million on the line of credit to offset its joint interest billings arising from costs under the Senegal Blocks petroleum agreements. The line of credit agreement was terminated in April 2017 when Timis entered into an agreement with BP to acquire Timis' 30% participating interest in the Senegal Blocks. As a result of the termination of this credit agreement, Kosmos received $16 million in August 2017 representing payment in full of outstanding amounts drawn on the line of credit.

In September 2017, we closed a farm-in agreement with Tullow Mauritania Limited, a subsidiary of Tullow Oil plc (“Tullow”), to acquire a 15% non-operated participating interest in Block C18 offshore Mauritania. Based on the terms of the agreement, we will reimburse a portion of past and interim period costs and partially carry future costs.

In October 2017, we entered into an agreement to acquire all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which holds an 85% paying interest (80.75% revenue interest) in the Ceiba Field and Okume Complex assets, through a joint venture with an affiliate of Trident Energy ("Trident"). Under the terms of the agreement, Kosmos and Trident will each own 50% of Hess International Petroleum Inc. Kosmos will be primarily responsible for exploration and subsurface evaluation while Trident will primarily be responsible for production operations and optimization. The transaction expands our position in the Gulf of Guinea and provides immediate cash flow through existing production with potential to increase existing production and also provides step-out exploration opportunities with potential tie-back through existing infrastructure. The gross acquisition price is $650 million effective as of January 1, 2017. Kosmos is expected to pay net cash consideration of approximately $240 million at close, subject to post-closing adjustments, with a combination of cash on hand and availability under the Facility. The transaction is expected to close by year end, subject to customary closing conditions, and will be accounted for as an equity method investment.

In October 2017, we also entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. Ratification of the petroleum contracts by the President of Equatorial Guinea is expected by the end of the year. We presently have an 80% interest and are the operator in all three blocks, but pursuant to an agreement with Trident we expect to assign a 40% interest in the blocks to an affiliate of Trident after completion of the Hess transaction. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the date of notification of ratification by the President of Equatorial Guinea. The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the three blocks. Upon closing of the Hess transaction and the assignment

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of a 40% interest to the Trident affiliate noted above, interests in these three blocks will be 40% Kosmos, 40% Trident and 20% GEPetrol.

4. Joint Interest Billings

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

In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s 5% share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues under the terms of the Deepwater Tano (“DT”) petroleum contract. As of September 30, 2017 and December 31, 2016, the joint interest billing receivables due from GNPC for the TEN development costs were $1.6 million and zero, respectively, which are classified as current and $47.5 million and $44.0 million, respectively, which are classified as long-term on the consolidated balance sheets.

5. Property and Equipment

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



	September 30, 2017			December 31, 2016
	(In thousands)
Oil and gas properties:
Proved properties	$	1,371,641		$	1,385,331
Unproved properties	651,921			919,056
Support equipment and facilities	1,391,613			1,386,448
Total oil and gas properties	3,415,175			3,690,835
Accumulated depletion	(1,163,198		)	(989,946		)
Oil and gas properties, net	2,251,977			2,700,889

Other property	38,124			37,186
Accumulated depreciation	(31,700		)	(29,183		)
Other property, net	6,424			8,003

Property and equipment, net	$	2,258,401		$	2,708,892

We recorded depletion expense of $70.9 million and $15.6 million for the three months ended September 30, 2017 and 2016, respectively, and $173.3 million and $59.6 million for the nine months ended September 30, 2017 and 2016, respectively.

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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, 2017. The table excludes $24.5 million in costs that were capitalized and subsequently expensed during the same period.



	September 30, 2017
	(In thousands)
Beginning balance	$	734,463
Additions to capitalized exploratory well costs pending the determination of proved reserves	67,543
Reclassification due to determination of proved reserves	—
Divestitures(1)	(206,400		)
Contribution of oil and gas property to equity method investment	(131,764		)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	463,842

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(1)	Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP.

The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:



	September 30, 2017		December 31, 2016
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	65,606	$	279,809
Exploratory well costs capitalized for a period of one to two years	184,486		244,804
Exploratory well costs capitalized for a period of three to eight years	213,750		209,850
Ending balance	$	463,842	$	734,463
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	6		5

As of September 30, 2017, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Mahogany, Teak (formerly Teak-1 and Teak-2) and Akasa discoveries in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border, the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Teranga discovery in the Cayar Offshore Profond block offshore Senegal.

Mahogany and Teak Discoveries — In October 2017, the Jubilee Unit was expanded to include the Mahogany and Teak discoveries. As part of the expansion of the Jubilee Unit, the capitalized exploratory well costs will be moved to proved property in the fourth quarter of 2017.

Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. The WCTP Block partners have agreed they will take the steps necessary to transfer operatorship of the remaining portions of the WCTP Block, including the Akasa Discovery, to Tullow after approval of the GJFFDP by Ghana’s Ministry of Energy.

Wawa Discovery — In February 2016, we requested the Ghana Ministry of Energy to approve the enlargement of the areal extent of the TEN fields and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. In April 2016, the Ghana Ministry of Energy approved our request to enlarge the TEN development and production area subject to continued subsurface and development concept evaluation, along

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with the requirement to integrate the Wawa Discovery into the TEN PoD. We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation.

Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania which encountered hydrocarbon pay. Two additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design (FEED) process. Following additional technical and commercial evaluation, a decision regarding commerciality will be made.

BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well (renamed BirAllah) in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made.

Teranga Discovery — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made.

7. Debt



	September 30, 2017			December 31, 2016
	(In thousands)
Outstanding debt principal balances:
Facility	$	600,000		$	850,000
Senior Notes	525,000			525,000
Total	1,125,000			1,375,000
Unamortized deferred financing costs and discounts(1)	(44,648		)	(53,126		)
Long-term debt, net	$	1,080,352		$	1,321,874

__________________________________


(1)	Includes $25.0 million and $30.3 million of unamortized deferred financing costs related to the Facility and $19.6 million and $22.8 million of unamortized deferred financing costs and discounts related to the Senior Notes as of September 30, 2017 and December 31, 2016, respectively.

Facility

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

In August 2017, following the lender’s waiver of the September 30, 2017 semi-annual redetermination, the borrowing base under our Facility will remain at $1.3 billion. The borrowing base calculation includes value related to the Jubilee and TEN fields. As of September 30, 2017, borrowings under the Facility totaled $600.0 million and the undrawn availability under the Facility was $700.8 million.

The Facility provides a revolving-credit and letter of credit facility. The availability period for the revolving-credit facility, as amended in March 2014, expires on March 31, 2018, however, the Facility has a revolving-credit sublimit, which will be the lesser of $500.0 million and the total available facility at that time, that will be available for drawing until the date falling one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2018, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2021. As of September 30, 2017, we had no letters of credit issued under the Facility.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2017 (the most recent assessment date). The Facility contains customary cross default provisions.

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Corporate Revolver

In June 2015, we amended and restated the Corporate Revolver from a number of financial institutions, increasing the borrowing capacity to $400.0 million, extending the maturity date to November 2018 and lowering the commitment fees on the undrawn portion of the total commitments to 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of September 30, 2017, we have $3.2 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 sheets.

As of September 30, 2017, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million. We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2017 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

In July 2016, we amended and restated the revolving letter of credit facility agreement (“LC Facility”), extending the maturity date to July 2019. During the first quarter of 2017, the LC Facility size was increased to $115.0 million. In April 2017, we reduced the size of our LC Facility to $70 million. As of September 30, 2017, there were eight outstanding letters of credit totaling $60.3 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.

The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries.

At September 30, 2017, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:



	Payments Due by Year
	Total		2017(2)		2018		2019		2020		2021		Thereafter
	(In thousands)
Principal debt repayments(1)	$	1,125,000	$	—	$	—	$	377	$	404,971	$	719,652	$	—

__________________________________

(1)

Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of September 30, 2017, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter. As of September 30, 2017, there were no borrowings under the Corporate Revolver.


(2)	Represents payments for the period October 1, 2017 through December 31, 2017.

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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,
	2017			2016			2017			2016
	(In thousands)
Interest expense	$	22,961		$	23,057		$	68,934		$	65,829
Amortization—deferred financing costs	2,551			2,551			7,653			7,653
Capitalized interest	(8,563		)	(15,545		)	(25,498		)	(49,575		)
Deferred interest	662			663			1,610			406
Interest income	(745		)	(485		)	(2,485		)	(1,319		)
Other, net	1,612			825			4,515			7,274
Interest and other financing costs, net	$	18,478		$	11,066		$	54,729		$	30,268

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.

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, 2017. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.



			Weighted Average Dated Brent Price per Bbl
			Deferred
			Premium
Term	Type of Contract	MBbl	Payable, Net		Swap		Sold Put		Floor		Ceiling		Call
2017:
October — December	Swap with puts/calls	503	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00
October — December	Swap with puts	503	—		64.95		50.00		—		—		—
October — December	Three-way collars	1,006	1.72		—		30.00		45.00		60.00		—
October — December	Sold calls(1)	500	—		—		—		—		85.00		—
2018:
January — December	Swap with puts	2,000	$	—	$	54.32	$	40.00	$	—	$	—	$	—
January — December	Three-way collars	2,913	0.74		—		41.57		56.57		65.90		—
January — December	Four-way collars	3,000	1.06		—		40.00		50.00		61.33		70.00
January — December	Sold calls(1)	2,000	—		—		—		—		65.00		—
2019:
January — December	Three-way collars	4,500	$	0.26	$	—	$	40.00	$	50.00	$	62.78	$	—
January — December	Sold calls(1)	913	—		—		—		—		80.00		—

__________________________________


(1)	Represents call option contracts sold to counterparties to enhance other derivative positions.

In October 2017, we entered into costless swap contracts for 1.0 MMBbl from January 2018 through June 2018 with a fixed price of $57.25 per barrel, and costless swaps and sold put contracts for 2.0 MMBbl from July 2018 through December 2

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018 with a weighted average fixed price of $57.96 per barrel and a weighted average sold put price of $45.00 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, 2017:

Weighted Average

Term

Type of Contract

Floating Rate

Notional

Swap

Sold Call

(In thousands)

October 2017 — December 2018

Capped swap

1-month LIBOR

200,000

1.23

3.00

The following tables disclose the Company’s derivative instruments as of September 30, 2017 and December 31, 2016 and gain/(loss) from derivatives during the three and nine months ended September 30, 2017 and 2016, respectively:



		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2017			December 31, 2016
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity(1)	Derivatives assets—current	$	15,811		$	31,698
Interest rate	Derivatives assets—current	389			—
Commodity(2)	Derivatives assets—long-term	2,107			3,226
Interest rate	Derivatives assets—long-term	305			582
Derivative liabilities:
Commodity(3)	Derivatives liabilities—current	(9,016		)	(19,163		)
Interest rate	Derivatives liabilities—current	—			(529		)
Commodity(4)	Derivatives liabilities—long-term	(7,256		)	(14,123		)
Total derivatives not designated as hedging instruments		$	2,340		$	1,691

__________________________________


(1)	Includes net deferred premiums payable of $2.0 million and $3.9 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(2)	Includes net deferred premiums payable of $0.7 million and $2.5 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(3)	Includes zero and $30.9 thousand as of September 30, 2017 and December 31, 2016, respectively, which represents our provisional oil sales contract. Also includes net deferred premiums payable of $4.4 million and $6.2 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.


(4)	Includes net deferred premiums payable of $2.1 million and $0.6 million related to commodity derivative contracts as of September 30, 2017 and December 31, 2016, respectively.

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		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)	2017			2016		2017			2016
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	(6,221	)	$	344	$	(10,781	)	$	(712	)
Commodity	Derivatives, net	(26,864		)	16,891		36,404			(33,752		)
Interest rate	Interest expense	64			760		301			(2,715		)
Total derivatives not designated as hedging instruments		$	(33,021	)	$	17,995	$	25,924		$	(37,179	)

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

Offsetting of Derivative Assets and Derivative Liabilities

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 2017 and December 31, 2016, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

9. Fair Value Measurements

In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not 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.

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, for each fair value hierarchy level:



	Fair Value Measurements Using:
	Quoted Prices in
	Active Markets for		Significant Other			Significant
	Identical Assets		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)		Total
	(In thousands)
September 30,2017
Assets:
Commodity derivatives	$	—	$	17,918		$	—	$	17,918
Interest rate derivatives	—		694			—		694
Liabilities:
Commodity derivatives	—		(16,272		)	—		(16,272		)
Interest rate derivatives	—		—			—		—
Total	$	—	$	2,340		$	—	$	2,340
December 31,2016
Assets:
Commodity derivatives	$	—	$	34,924		$	—	$	34,924
Interest rate derivatives	—		582			—		582
Liabilities:
Commodity derivatives	—		(33,286		)	—		(33,286		)
Interest rate derivatives	—		(529		)	—		(529		)
Total	$	—	$	1,691		$	—	$	1,691

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

Commodity Derivatives

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

Provisional Oil Sales

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

Interest Rate Derivatives

We enter into interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate. We also enter into capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is

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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, 2017 and December 31, 2016:



	September 30, 2017				December 31, 2016
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	506,594	$	545,874	$	503,716	$	528,938
Facility	600,000		600,000		850,000		850,000
Total	$	1,106,594	$	1,145,874	$	1,353,716	$	1,378,938

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

10. Equity-based Compensation

Restricted Stock Awards and Restricted Stock Units

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long-Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of $9.6 million and $9.2 million during the three months ended September 30, 2017 and 2016, respectively, and $29.9 million and $30.4 million during the nine months ended September 30, 2017 and 2016, respectively. The total tax benefit for the three months ended September 30, 2017 and 2016 was $3.2 million and $3.0 million, respectively, and $9.9 million and $9.9 million during the nine months ended September 30, 2017 and 2016, respectively. Additionally, we recorded a net tax shortfall related to equity-based compensation of $0.2 million and $1.0 million for the three months ended September 30, 2017 and 2016, respectively, and $3.1 million and $5.3 million during the nine months ended September 30, 2017 and 2016, respectively. The fair value of awards vested during the three months ended September 30, 2017 and 2016 was approximately $1.4 million and $2.4 million, respectively, and $20.7 million and $13.4 million during the nine months ended September 30, 2017 and 2016, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units with a combination of market and service vesting criteria under the LTIP. Substantially all these awards vest over three or four year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.

The following table reflects the outstanding restricted stock awards as of September 30, 2017:



			Weighted-
	Service Vesting		Average
	Restricted Stock		Grant-Date
	Awards		Fair Value
	(In thousands)
Outstanding at December 31, 2016	488		$	8.83
Granted	—		—
Forfeited	—		—
Vested	(268	)	8.97
Outstanding at September 30, 2017	220		8.64

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The following table reflects the outstanding restricted stock units as of September 30, 2017:



			Weighted-		Market / Service		Weighted-
	Service Vesting		Average		Vesting		Average
	Restricted Stock		Grant-Date		Restricted Stock		Grant-Date
	Units		Fair Value		Units		Fair Value
	(In thousands)				(In thousands)
Outstanding at December 31, 2016	4,160		$	6.91	7,194		$	12.29
Granted	2,063		6.41		2,170		9.50
Forfeited	(123	)	7.03		(27	)	7.76
Vested	(1,864	)	7.50		(894	)	15.44
Outstanding at September 30, 2017	4,236		6.40		8,443		11.26

As of September 30, 2017, total equity-based compensation to be recognized on unvested restricted stock awards and restricted stock units is $33.5 million over a weighted average period of 1.48 years. At September 30, 2017, the Company had approximately 3.4 million shares that remain available for issuance under the LTIP.

For restricted stock awards and restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 100% of the awards granted for restricted stock awards and up to 200% of the awards granted for restricted stock units. The grant date fair value was $9.45 per award for restricted stock awards and ranged from $4.83 to $15.81 per award for restricted stock units. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and was 55.0% for the restricted stock awards and ranged from 44.0% to 54.0% for restricted stock units. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and was 0.5% for restricted stock awards and ranged from 0.5% to 1.4% for restricted stock units.

11. Income Taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate.

The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with a 0% statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Bermuda	$	(17,740	)	$	(15,989	)	$	(50,680	)	$	(47,212	)
United States	1,437			1,132			4,231			5,447
Foreign—other	(48,617		)	(37,404		)	(9,863		)	(195,379		)
Income (loss) before income taxes	$	(64,920	)	$	(52,261	)	$	(56,312	)	$	(237,144	)

Our effective tax rate for the three months ended September 30, 2017 and 2016 is 2% and 14%, respectively. For the nine months ended, September 30, 2017 and 2016, our effective tax rate was 79% and 4%, respectively. The effective tax rate is impacted by the effect of equity-based compensation tax shortfalls and windfalls equal to the difference between the income tax benefit recognized for financial statement purposes and the income tax benefit realized for tax return purposes and by non-deductible

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expenditures associated with the damage to the turret bearing, due to the expected recovery from insurance proceeds. Any such insurance recoveries would not be subject to income tax.

The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are Ghana and the United States. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2016 and in the United States, to federal income tax examinations for tax years 2013 through 2016.

As of September 30, 2017, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

12. Net Loss Per Share

The following table is a reconciliation between net loss and the amounts used to compute basic and diluted net loss per share and the weighted average shares outstanding used to compute basic and diluted net loss per share:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Numerator:
Net loss	$	(63,405	)	$	(59,763	)	$	(100,713	)	$	(227,080	)
Basic income allocable to participating securities(1)	—			—			—			—
Basic net loss allocable to common shareholders	(63,405		)	(59,763		)	(100,713		)	(227,080		)
Diluted adjustments to income allocable to participating securities(1)	—			—			—			—
Diluted net loss allocable to common shareholders	$	(63,405	)	$	(59,763	)	$	(100,713	)	$	(227,080	)
Denominator:
Weighted average number of shares outstanding:
Basic	389,058			386,026			388,114			385,130
Restricted stock awards and units(1)(2)	—			—			—			—
Diluted	389,058			386,026			388,114			385,130
Net loss per share:
Basic	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)
Diluted	$	(0.16	)	$	(0.15	)	$	(0.26	)	$	(0.59	)

__________________________________

(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 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 loss per common share calculation in periods we are in a net loss position.


(2)	We excluded outstanding restricted stock awards and units of 12.9 million and 12.0 million for the three and nine months ended September 30, 2017 and 2016, respectively, from the computations of diluted net loss 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.

We currently have a commitment to drill two exploration wells in Mauritania. In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to their maximum $228 million cumulative exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea, Mauritania and Western Sahara, we have 3D seismic requirements of 6,000 square kilometers, 7,600 square kilometers and 5,000 square kilometers, respectively. Additionally, in Morocco certain geological studies are also required. The Equatorial Guinea block commitments are subject to ratification by the President of Equatorial Guinea.

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In January 2017, Kosmos Energy Ventures (“KEV”), a subsidiary of Kosmos Energy Ltd., elected to cancel the fourth year option of the ENSCO DS-12 (formerly the Atwood Achiever) drilling rig contract and revert to the original day rate of approximately $0.6 million per day and original agreement end date of November 2017. During the first quarter of 2017, KEV made a rate recovery payment of $48.1 million representing the difference between the original day rate and the amended day rate multiplied by the number of days from the amendment effective date to the date the election was exercised plus certain administrative costs which was recorded as exploration expense.

Future minimum rental commitments under our leases at September 30, 2017, are as follows:



	Payments Due By Year(1)
	Total		2017(2)		2018		2019		2020		2021		Thereafter
	(In thousands)
Operating leases(3)	$	9,910	$	1,158	$	4,736	$	3,951	$	65	$	—	$	—
ENSCO DS-12 drilling rig contract	25,585		25,585		—		—		—		—		—

__________________________________


(1)	Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.


(2)	Represents payments for the period from October 1, 2017 through December 31, 2017.


(3)	Primarily relates to corporate office and foreign office leases.

14. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:



	September 30, 2017		December 31, 2016
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	130,543	$	76,194
General and administrative expenses	26,823		31,243
Interest	9,180		17,247
Income taxes	3,145		2,579
Taxes other than income	3,941		1,914
Other	172		529
	$	173,804	$	129,706

Other Income, Net

Other income, net consisted of zero Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended September 30, 2017 and 2016, and $58.7 million and $20.0 million for the nine months ended September 30, 2017 and 2016, respectively. Our LOPI coverage for this incident ended in May 2017.

Oil and gas production

Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of zero for the three months ended September 30, 2017 and 2016, and $17.1 million and zero, for the nine months ended September 30, 2017 and 2016, respectively.

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Facilities Insurance Modifications, Net

Facilities insurance modifications, net consists of costs associated with the conversion of the Jubilee FPSO to a permanently spread moored facility, net of related insurance proceeds.

Other Expenses, Net

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(In thousands)
Inventory write-off	$	(500	)	$	—		$	47		$	15,177
(Gain) loss on insurance settlements	—			(3,047		)	(461		)	(4,003		)
Disputed charges and related costs	821			1,826			3,260			1,826
Loss on equity method investment	4,804			—			11,230			—
Other, net	(88		)	426			157			768
Other expenses, net	$	5,037		$	(795	)	$	14,233		$	13,768

The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputes that these expenditures are properly chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.

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Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2016, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are a leading independent oil and gas exploration and production company focused on frontier and emerging areas along the Atlantic Margins. Our assets include existing production and development projects offshore Ghana, large discoveries and significant further hydrocarbon exploration potential offshore Mauritania and Senegal, as well as exploration licenses with significant hydrocarbon potential offshore Sao Tome and Principe, Suriname, Morocco and Western Sahara.

Recent Developments

Corporate

In August 2017, we announced that our entire issued and outstanding share capital has been admitted to the standard listing segment of the Official List of the Financial Conduct Authority and to trading on the London Stock Exchange’s main market for listed securities under the ticker “KOS”. The listing is expected to broaden Kosmos’ international investor base and provide access to an additional pool of capital.

The availability period for the Facility, as amended in March 2014, expires on March 31, 2018 and the letter of credit sublimit expires on the final maturity date of March 31, 2021. The first required payment could be as early as September 30, 2019, subject to the level of outstanding borrowings and the borrowing base constraints. We are currently in discussions with our lenders to refinance the Facility during the first quarter of 2018 to extend the availability period as well as include reserves for Equatorial Guinea.

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 Jubilee turret remediation work is progressing as planned and the FPSO spread-mooring at its current heading was completed in February 2017. This allowed the tug boats previously required to hold the vessel on a fixed heading to be removed, significantly reducing the cost and complexity of the current operation. The next phase of the remediation work involves lifting and locking the main bearing. The partners and the government of Ghana have agreed on the need to lift and lock the turret bearing and a shutdown is being planned in early 2018 to execute this workscope. Planning for the rotation of the vessel and the installation of a deepwater CALM buoy is ongoing, subject to final decisions and government approval. Total shutdown duration, for lifting and locking, rotation and offloading system installation, is not expected to exceed 12 weeks as previously forecast by the Operator.

The financial impact of lower Jubilee production as well as the additional expenditures associated with the damage to the turret bearing is being mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos. Our LOPI coverage for this incident ended in May 2017 and final claim amounts have been approved with remaining cash proceeds received in August 2017.

The Greater Jubilee Full Field Development Plan (“GJFFDP”) was resubmitted to the government of Ghana in September 2017 and subsequently approved in October 2017. This plan, which is expected to increase proved reserves and extend the field production profile, has been optimized to reduce overall capital expenditures to reflect the current oil price market. In November 2015, we signed the Jubilee Field Unit Expansion Agreement with our partners, which became effective upon approval of the GJFFDP, to allow for the development of the Mahogany and Teak discoveries through the Jubilee FPSO and infrastructure, thus reducing their development cost. Upon approval of the GJFFDP by the Ministry of Energy in October 2017, operatorship for

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the Mahogany and Teak discoveries transferred to Tullow. The WCTP Block partners are in the process of taking the steps necessary to transfer operatorship of the remaining portions of the WCTP Block to Tullow.

Tweneboa, Enyenra and Ntomme (“TEN”)

In September 2017, the Special Chamber of the International Tribunal of the Sea (ITLOS) issued its final decision in the maritime boundary dispute between the Governments of Ghana and Cote d'Ivoire. The maritime boundary delimited by the Special Chamber's decision has no impact on TEN production or reserves or otherwise on the company's interests in Ghana. Production from TEN in the nine months ended September 30, 2017 averaged approximately 52,000 bopd and is on track to achieve or exceed the operator’s 2017 guidance of 50,000 bopd. After resuming drilling, the TEN fields are expected to increase production towards FPSO capacity of 80,000 bopd as development progresses.

Greater Tortue Discovery

In August 2017, we announced the successful completion of the drill stem test ("DST") of the Tortue-1 well, demonstrating that the Tortue field is a world-class resource and confirming key development parameters including well deliverability, reservoir connectivity, and fluid composition. The Tortue-1 well flowed at a sustained, equipment-constrained rate of approximately 60 million cubic feet per day (MMcfd) during the main extended flow period, with minimal pressure drawdown, providing confidence in well designs that are each capable of producing approximately 200 MMcfd. The DST results confirmed a connected volume per well consistent with the current development scheme, which together with the high well rate is expected to result in a low number of development wells compared to equivalent schemes. Initial analysis of fluid samples collected during the test indicate Tortue gas is well suited for liquefaction given low levels of liquids and minimal impurities. Data acquired from the DST will be used to further optimize field development and to refine process design parameters critical to the front end engineering and design ("FEED") process.

Senegal (Kosmos BP Senegal Limited (“KBSL”) – equity method investment)

In October 2017, KBSL transferred a 30% working interest in the Cayar offshore Profond and Saint Louis Offshore Profond blocks offshore Senegal to BP Senegal Investments Limited in exchange for their outstanding shares of KBSL which was approved, resulting in KBSL becoming a wholly-owned subsidiary of Kosmos. After the transfer, KBSL has a 30% working interest in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") offshore Senegal and therefore, KBSL will no longer be accounted for under the equity method of accounting.

Mauritania

Drilling of the Hippocampe-1 exploration well on the C8 block was completed in October 2017. Designed to test Lower Cenomanian and Albian reservoirs, the well was drilled to a total depth of approximately 5,500 meters. Well-developed reservoirs were encountered in both exploration targets, but these proved to be water bearing. The well has been plugged and abandoned. Total well and other related costs of $21.0 million incurred from inception through September 30, 2017 are included in exploration expenses in the accompanying consolidated statement of operations. We estimate an additional $10.6 million of related well costs will be incurred in the fourth quarter, and will be expensed when incurred.

Sao Tome and Principe

In August 2017, we completed a 3D seismic survey of approximately 15,800 square kilometers over Blocks 5, 6, 11 and 12 offshore Sao Tome and Principe.

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Equatorial Guinea

In October 2017, we also entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. Ratification of the petroleum contracts by the President of Equatorial Guinea is expected by the end of the year. We presently have an 80% interest and are the operator in all three blocks, but pursuant to an agreement with Trident we expect to assign a 40% interest in the blocks to an affiliate of Trident after completion of the Hess transaction. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), currently has a 20% carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest. The petroleum contracts cover approximately 6,000 square kilometers, with a first exploration period of five years from the date of notification of ratification by the President of Equatorial Guinea. The first exploration period consists of two sub-periods of three and two years, respectively. The first exploration sub-period work program includes a 6,000 square kilometer 3D seismic acquisition requirement across the blocks. Upon closing of the Hess transaction and the assignment of a 40% interest to the Trident affiliate noted above, interests in these three blocks will be 40% Kosmos, 40% Trident and 20% GEPetrol.

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Results of Operations

All of our results, as presented in the table below, represent operations in Ghana. Certain operating results and statistics for the three and nine months ended September 30, 2017 and 2016 are included in the following table:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(In thousands, except per barrel data)
Sales volumes (MBbl):
Jubilee	1,943		947		5,838		3,791
TEN	996		—		1,992		—
Total sales volumes	2,939		947		7,830		3,791

Revenues:
Oil and gas sales	$	151,240	$	46,628	$	391,035	$	154,259
Average sales price per Boe	51.46		49.24		49.94		40.69

Costs:
Oil and gas production, excluding workovers	$	38,118	$	13,525	$	79,110	$	75,587
Oil and gas production, workovers	1,069		49		1,567		60
Total oil and gas production costs	$	39,187	$	13,574	$	80,677	$	75,647

Depletion and depreciation	$	73,490	$	17,838	$	180,909	$	66,031

Average cost per Boe:
Oil and gas production, excluding workovers	$	12.97	$	14.28	$	10.10	$	19.94
Oil and gas production, workovers	0.36		0.05		0.20		0.02
Total oil production costs	13.33		14.33		10.30		19.96

Depletion and depreciation	25.01		18.84		23.10		17.42
Oil and gas production cost and depletion costs	$	38.34	$	33.17	$	33.40	$	37.38

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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, 2017:



	Actively Drilling or				Wells Suspended or
	Completing				Waiting on Completion
	Exploration		Development		Exploration		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Ghana
Jubilee Unit	—	—	—	—	—	—	2	0.48
West Cape Three Points	—	—	—	—	9	2.78	—	—
TEN	—	—	—	—	—	—	5	0.85
Deepwater Tano	—	—	—	—	1	0.18	—	—
Mauritania
C8	1	0.28	—	—	3	0.84	—	—
Senegal (KBSL - equity method investment)
Saint Louis Offshore Profond	—	—	—	—	1	0.30	—	—
Cayar Profond	—	—	—	—	2	0.60	—	—
Total	1	0.28	—	—	16	4.70	7	1.33

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, 2017 compared to three months ended September 30, 2016



	Three Months Ended
	September 30,						Increase
	2017			2016			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	151,240		$	46,628		$	104,612
Other income, net	2			20,001			(19,999		)
Total revenues and other income	151,242			66,629			84,613
Costs and expenses:
Oil and gas production	39,187			13,574			25,613
Facilities insurance modifications, net	(3,906		)	5,946			(9,852		)
Exploration expenses	36,983			66,238			(29,255		)
General and administrative	20,029			21,914			(1,885		)
Depletion and depreciation	73,490			17,838			55,652
Interest and other financing costs, net	18,478			11,066			7,412
Derivatives, net	26,864			(16,891		)	43,755
Other expenses, net	5,037			(795		)	5,832
Total costs and expenses	216,162			118,890			97,272
Loss before income taxes	(64,920		)	(52,261		)	(12,659		)
Income tax expense (benefit)	(1,515		)	7,502			(9,017		)
Net loss	$	(63,405	)	$	(59,763	)	$	(3,642	)

Oil and gas revenue. Oil and gas revenue increased by $104.6 million as a result of three cargos sold during the three months ended September 30, 2017, compared to one cargo sold during the three months ended September 30, 2016. We lifted and

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sold 2,939 MBbl at an average realized price per barrel of $51.46 during the three months ended September 30, 2017 and 947 MBbl at an average realized price per barrel of $49.24 during the three months ended September 30, 2016.

Other income, net. Other income, net decreased by $20.0 million as we recognized $20.0 million of LOPI proceeds, net during the three months ended September 30, 2016 related to the turret bearing issue on the Jubilee FPSO. The LOPI claim was finalized in June 2017.

Oil and gas production. Oil and gas production costs increased by $25.6 million during the three months ended September 30, 2017, as compared to the three months ended September 30, 2016 as a result of costs related to the sale of three cargos of oil, including one TEN cargo, as compared to one Jubilee cargo for the respective periods.

Facilities insurance modifications, net. During the three months ended September 30, 2017, we incurred $3.3 million of facilities insurance modifications costs associated with the long-term solution to the turret bearing issue. These costs were offset by $7.2 million of hull and machinery insurance proceeds received during the three months ended September 30, 2017 resulting in a credit of $3.9 million. 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 with no insurance recoveries.

Exploration expenses. Exploration expenses decreased by $29.3 million during the three months ended September 30, 2017, as compared to the three months ended September 30, 2016. The change is primarily a result of $46.8 million of stacked rig costs associated with the ENSCO DS-12 (formerly the Atwood Achiever) incurred during the three months ended September 30, 2016, which is partially offset by an increase in unsuccessful well costs for the Mauritania Hippocampe-1 exploration well incurred during the three months ended September 30, 2017.

General and administrative. General and administrative costs decreased by $1.9 million during the three months ended September 30, 2017, as compared with the three months ended September 30, 2016. The decrease is primarily a result of carried costs associated with the BP transactions.

Depletion and depreciation. Depletion and depreciation increased $55.7 million during the three months ended September 30, 2017, as compared with the three months ended September 30, 2016. The increase is primarily a result of depletion recognized related to the sale of three cargos of oil, including one TEN cargo, during the three months ended September 30, 2017, as compared to one Jubilee cargo during the three months ended September 30, 2016. In addition, the 2017 depletion rate is higher as a result of a decrease in recognized proved reserves associated with the Jubilee Field in the fourth quarter of 2016 and a higher depletion rate for the TEN fields.

Interest and other financing costs, net. Interest and other financing costs, net increased $7.4 million primarily a result of the TEN fields coming online in August 2016, which resulted in a $7.0 million decrease in capitalized interest.

Derivatives, net. During the three months ended September 30, 2017 and 2016, we recorded a loss of $26.9 million and a gain of $16.9 million, respectively, on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net increased $5.8 million primarily related to a $4.8 million loss on equity method investment in KBSL during the three months ended September 30, 2017. During the three months ended September 30, 2016, we recorded a $3.0 million gain on insurance settlement offset by $1.8 million of arbitration related legal fees.

Income tax expense (benefit). The Company’s effective tax rates for the three months ended September 30, 2017 and 2016 were 2% and 14%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. The effective tax rate in Ghana is impacted by the timing of non-deductible expenditures incurred associated with the damage to the turret bearing, due to the expected recovery from insurance proceeds. Any such insurance recoveries would not be subject to income tax. Income tax expense decreased $9.0 million during the three months ended September 30, 2017, as compared with September 30, 2016, primarily as a result of mark to market losses on our oil derivatives during the current period compared to gains in the prior year period, higher operating expenses, and higher depletion and depreciation expense associated with TEN production, partially offset by higher oil revenue in Ghana,

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Nine months ended September 30, 2017 compared to nine months ended September 30, 2016



	Nine Months Ended
	September 30,						Increase
	2017			2016			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	391,035		$	154,259		$	236,776
Other income, net	58,697			20,179			38,518
Total revenues and other income	449,732			174,438			275,294
Costs and expenses:
Oil and gas production	80,677			75,647			5,030
Facilities insurance modifications, net	(1,334		)	5,946			(7,280		)
Exploration expenses	162,679			126,498			36,181
General and administrative	50,555			59,672			(9,117		)
Depletion and depreciation	180,909			66,031			114,878
Interest and other financing costs, net	54,729			30,268			24,461
Derivatives, net	(36,404		)	33,752			(70,156		)
Other expenses, net	14,233			13,768			465
Total costs and expenses	506,044			411,582			94,462
Loss before income taxes	(56,312		)	(237,144		)	180,832
Income tax expense (benefit)	44,401			(10,064		)	54,465
Net loss	$	(100,713	)	$	(227,080	)	$	126,367

Oil and gas revenue. Oil and gas revenue increased by $236.8 million as a result of eight cargos sold during the nine months ended September 30, 2017, compared to four cargos sold during the nine months ended September 30, 2016 at a higher average realized price. We lifted and sold 7,830 MBbl at an average realized price per barrel of $49.94 during the nine months ended September 30, 2017 and 3,791 MBbl at an average realized price per barrel of $40.69 during the nine months ended September 30, 2016.

Other income, net. Other income, net increased by $38.5 million as we recognized $58.7 million of LOPI proceeds, net during the nine months ended September 30, 2017 related to the turret bearing issue on the Jubilee FPSO compared to $20.0 million of LOPI proceeds in the previous period. The LOPI claim was finalized in June 2017.

Oil and gas production. Oil and gas production costs increased by $5.0 million during the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016 as a result of lower LOPI claim insurance proceeds recognized during the nine months ended September 30, 2017 offset by accrual adjustments from the Jubilee and TEN fields operator. The LOPI claim was finalized in June 2017.

Facilities insurance modifications, net. During the nine months ended September 30, 2017, we incurred $13.6 million of facilities insurance modifications costs associated with the long-term solution to the turret bearing issue. These costs were offset by $14.9 million of hull and machinery insurance proceeds received during the nine months ended September 30, 2017 resulting in a credit of $1.3 million. 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 with no insurance recoveries.

Exploration expenses. Exploration expenses increased by $36.2 million during the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. The increase is primarily a result of a $48.1 million cancellation payment related to the exercise of our election to cancel the fourth year option of the ENSCO DS-12 drilling rig contract which is partially mitigated by a decrease of $21.1 million of stacked rig costs associated with the ESNSCO DS-12 incurred during the nine months ended September 30, 2017 as compared with the nine months ended September 30, 2016. Additionally, there were increases of $21.0 million of unsuccessful well costs for the Mauritania Hippocampe-1 exploration well and $5.6 million in new ventures costs partially offset by a decrease of $17.9 million in geological and geophysical costs incurred during the nine months ended September 30, 2017 as compared with the nine months ended September 30, 2016.

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General and administrative. General and administrative costs decreased by $9.1 million during the nine months ended September 30, 2017, as compared with the nine months ended September 30, 2016. The decrease is primarily a result of carried costs associated with the BP transactions, accrual adjustments from the Jubilee and TEN fields operator, and to a lesser extent a decrease in non-cash stock-based compensation.

Depletion and depreciation. Depletion and depreciation increased $114.9 million during the nine months ended September 30, 2017, as compared with the nine months ended September 30, 2016. The increase is primarily a result of depletion recognized related to the sale of eight cargos of oil during the nine months ended September 30, 2017, as compared to four cargos during the nine months ended September 30, 2016. In addition, the 2017 depletion rate is higher as a result of a decrease in recognized proved reserves associated with the Jubilee Field in the fourth quarter of 2016 and a higher depletion rate for the TEN fields.

Interest and other financing costs, net. Interest and other financing costs, net increased $24.5 million primarily a result of the TEN fields coming online in August 2016, which resulted in a $24.1 million decrease in capitalized interest during 2017.

Derivatives, net. During the nine months ended September 30, 2017 and 2016, we recorded gain of $36.4 million and a loss of $33.8 million, respectively, on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net increased $0.5 million primarily due to a $15.2 million impairment of inventory recorded during the nine months ended September 30, 2016, compared to a $11.2 million loss recognized on our equity method investment in KBSL and arbitration related legal fees recorded during the nine months ended, September 30, 2017.

Income tax expense (benefit). The Company’s effective tax rates for the nine months ended September 30, 2017 and 2016 were 79% and 4%, respectively. The effective tax rates for the periods presented were impacted by losses, primarily related to exploration expenses, incurred in jurisdictions in which we are not subject to taxes and losses incurred in jurisdictions in which we have valuation allowances against our deferred tax assets and therefore we do not realize any tax benefit on such expenses or losses. The effective tax rate in Ghana is impacted by the timing of non-deductible expenditures incurred associated with the damage to the turret bearing, due to the expected recovery from insurance proceeds. Any such insurance recoveries would not be subject to income tax. Income tax expense increased $54.5 million during the nine months ended September 30, 2017, as compared with September 30, 2016, primarily as a result of higher oil revenue in Ghana and mark to market gains on our oil derivatives, partially offset by higher depletion and depreciation expense associated with TEN production.

Liquidity and Capital Resources

We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margins. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt as well as partner carries. In relation to cash flow generated from our operating activities, if we are unable to continuously export associated natural gas in large quantities, which causes potential production restraints, then the Company’s cash flows from operations will be adversely affected. In the past we have experienced equipment failures on the FPSOs, and we are currently working to remediate the turret bearing issue on the Jubilee FPSO. 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 bearing issue.

While we are presently in a strong financial position, a future decline in oil prices, if prolonged, could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. It could also impact the borrowing base available under the Facility or the related debt covenants. Commodity prices are volatile and future prices cannot be accurately predicted. We maintain a hedging program to partially mitigate the price volatility. Our investment decisions are based on longer-term commodity prices based on the long-term nature of our projects and development plans. Also, BP has agreed to partially carry our exploration, appraisal and development program in Mauritania and Senegal over the next several years. Current commodity prices, our hedging program, partner carries and our current liquidity position support our capital program for 2017, which 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

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to capital plans, 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, 2017 and 2016:



	Nine Months Ended
	September 30,
	2017			2016
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by (used in) operating activities	$	94,412		$	(65,623	)
Borrowings under long-term debt	—			450,000
Proceeds on sale of assets	222,068			210
	316,480			384,587
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	100,712			506,256
Other property	1,639			1,003
Payments on long-term debt	250,000			—
Purchase of treasury stock	2,116			1,930
	354,467			509,189
Decrease in cash, cash equivalents and restricted cash	$	(37,987	)	$	(124,602	)

Net cash provided by (used in) operating activities. Net cash provided by operating activities for the nine months ended September 30, 2017 was $94.4 million compared with net cash used in operating activities for the nine months ended September 30, 2016 of $65.6 million. The increase in cash provided by operating activities in the nine months ended September 30, 2017 when compared to the same period in 2016 is primarily a result of an increase in oil and gas revenue and LOPI proceeds, net partially offset by an increase in exploration expense related to the stacked rig costs and rig option cancellation payment as well as a decrease in derivative cash settlements.

The following table presents our net debt and liquidity as of September 30, 2017:



	September 30, 2017
	(In thousands)
Cash and cash equivalents	$	164,162
Restricted cash	71,046
Senior Notes at par	525,000
Drawings under the Facility	600,000
Net debt	$	889,792

Availability under the Facility	$	700,811
Availability under the Corporate Revolver	$	400,000
Available borrowings plus cash and cash equivalents	$	1,264,973

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Capital Expenditures and Investments

We expect to incur capital costs as we:


•	fund asset integrity projects at Jubilee;


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


•	acquire and analyze seismic, perform new ventures and manage our rig activities.

We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our participating and carried interests in our prospects including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects, our ability to utilize our available drilling rig capacity, the availability of suitable equipment and qualified personnel and our cash flows from operations. We also evaluate potential corporate and asset acquisition opportunities to support and expand our asset portfolio which may impact our budget assumptions. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.

2017 Capital Program

We estimate we will spend approximately $100 million of capital, net of carry amounts related to the Mauritania and Senegal transactions with BP, for the year ending December 31, 2017. Additionally, we expect to incur approximately $240 million, subject to post-closing adjustments, associated with the acquisition of the Ceiba Field and Okume Complex assets offshore Equatorial Guinea. Through September 30, 2017, we have spent approximately $217 million which was offset by the initial proceeds from the BP transaction of $222 million resulting in a credit to our capital budget of $5 million.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our drilling results among other factors. We resumed our previously suspended drilling program during the first quarter of 2017. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and the prices we receive from the sale of oil, our ability to effectively hedge future production volumes, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners’ alignment with respect to capital plans, and the actual cost of exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.

Significant Sources of Capital

Facility

In March 2014, we amended and restated the commercial debt facility (the “Facility”) with a total commitment of $1.5 billion from a number of financial institutions. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2017 (the most recent assessment date). The Facility contains customary cross default provisions.

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to refinance the Facility during the first quarter of 2018 to extend the availability period as well as include reserves for Equatorial Guinea.

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, 2017, there were no borrowings outstanding under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million.

We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2017 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

In July 2016, we amended and restated the revolving letter of credit facility agreement (“LC Facility”), extending the maturity date to July 2019. During the first quarter of 2017, the LC Facility size was $115.0 million. In April 2017, we reduced the size of our LC Facility to $70 million. As of September 30, 2017, there were eight outstanding letters of credit totaling $60.3 million under the LC Facility. The LC Facility contains customary cross default provisions.

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.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2017:



	Payments Due By Year(5)
	Total		2017(6)		2018		2019		2020		2021		Thereafter
	(In thousands)
Principal debt repayments(1)	$	1,125,000	$	—	$	—	$	377	$	404,971	$	719,652	$	—
Interest payments on long-term debt(2)	281,477		11,406		82,056		75,351		67,448		45,216		—
Operating leases(3)	9,910		1,158		4,736		3,951		65		—		—
ENSCO DS-12 drilling rig contract(4)	25,585		25,585		—		—		—		—		—

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(1)


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


(3)	Primarily relates to corporate office and foreign office leases.


(4)	In January 2017, Kosmos Energy Ventures (“KEV”) exercised its option to cancel the fourth year and revert to the original day rate of approximately $0.6 million per day and original agreement end date in November 2017. Commitments were calculated using the original day rate of $0.6 million, excluding applicable taxes.


(5)	Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts.


(6)	Represents the period from October 1, 2017 through December 31, 2017.

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



																		Asset
																		(Liability)
																		Fair Value at
	Years Ending December 31,																	September 30,
	2017(5)			2018			2019			2020			2021			Thereafter		2017
	(In thousands, except percentages)
Fixed rate debt:
Senior Notes	$	—		$	—		$	—		$	—		$	525,000		$	—	$	(545,874	)
Fixed interest rate	7.88		%	7.88		%	7.88		%	7.88		%	7.88		%	—
Variable rate debt:
Facility(1)	$	—		$	—		$	377		$	404,971		$	194,652		$	—	$	(600,000	)
Weighted average interest rate(2)	4.50		%	5.19		%	5.59		%	6.18		%	6.55		%	—
Capped interest rate swaps:
Notional debt amount	$	200,000		$	200,000		$	—		$	—		$	—		$	—	$	694
Cap	3.00		%	3.00		%	—			—			—			—
Average fixed rate payable(3)	1.23		%	1.23		%	—			—			—			—
Variable rate receivable(4)	1.26		%	1.57		%	—			—			—			—

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(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, 2017. 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, 2017, there were no borrowings under the Corporate Revolver.


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

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


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


(5)	Represents the period October 1, 2017 through December 31, 2017.

Off-Balance Sheet Arrangements

As of September 30, 2017, our material off-balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.

Critical Accounting Policies

We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and natural gas reserves, asset retirement obligations and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended December 31, 2016, other than as follows:

Consolidations / Equity Method of Accounting

The Consolidated Financial Statements include the accounts of our wholly-owned subsidiaries. They also include Kosmos’ share of the undivided interest in certain assets, liabilities, revenues and expenses. Investments in corporate joint ventures, which we exercise significant influence over, are accounted for using the equity method of accounting.

Equity method investments are integral to our operations. The other parties, who also have an equity interest in these companies, are independent third parties. Kosmos does not invest in these companies in order to remove liabilities from its balance sheet.

Cautionary Note Regarding Forward-looking Statements

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


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


•	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, 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;

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•	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;


•	environmental liabilities;


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


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


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


•	our vulnerability to severe weather events;


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


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


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


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


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


•	other risk factors discussed in the “Item 1A. Risk Factors” section of this quarterly report on Form 10-Q and our annual report on Form 10-K.

The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this quarterly report on Form 10-Q might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.

Item 3. Qualitative and Quantitative Disclosures About Market Risk

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

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

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The following table reconciles the changes that occurred in fair values of our open derivative contracts during the nine months ended September 30, 2017:



	Derivative Contracts Assets (Liabilities)
	Commodities			Interest Rates		Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2016	$	1,638		$	53	$	1,691
Changes in contract fair value	25,623			301		25,924
Contract maturities	(25,615		)	340		(25,275		)
Fair value of contracts outstanding as of September 30, 2017	$	1,646		$	694	$	2,340

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, 2017 ranged between $44.28 and $59.27.

Commodity Derivative Instruments

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

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, 2017. Volumes and weighted average prices 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, Net		Swap		Sold Put		Floor		Ceiling		Call		2017(2)
															(In thousands)
2017:
October — December	Swap with puts/calls	503	$	2.13	$	72.50	$	55.00	$	—	$	—	$	90.00	$	6,348
October — December	Swap with puts	503	—		64.95		50.00		—		—		—		4,073
October — December	Three-way collars	1,006	1.72		—		30.00		45.00		60.00		—		(2,171		)
October — December	Sold calls(1)	500	—		—		—		—		85.00		—		—
2018:
January — December	Swap with puts	2,000	$	—	$	54.32	$	40.00	$	—	$	—	$	—	$	(3,611	)
January — December	Three-way collars	2,913	0.74		—		41.57		56.57		65.90		—		6,202
January — December	Four-way collars	3,000	1.06		—		40.00		50.00		61.33		70.00		(2,589		)
January — December	Sold calls(1)	2,000	—		—		—		—		65.00		—		(2,624		)
2019:
January — December	Three-way collars	4,500	$	0.26	$	—	$	40.00	$	50.00	$	62.78	$	—	$	(3,609	)
January — December	Sold calls(1)	913	—		—		—		—		80.00		—		(373		)

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(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, 2017 which by year are: 2017 — $56.38, 2018 — $55.51 and 2019 — $54.77. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on November 1, 2017 market quotes by year are: 2017 — $60.57, 2018 — $58.72 and 2019 — $56.53.

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In October 2017, we entered into costless swap contracts for 1.0 MMBbl from January 2018 through June 2018 with a fixed price of $57.25 per barrel; and costless swap and sold put contracts for 2.0 MMBbl from July 2018 through December 2018 with a weighted average fixed price of $57.96 per barrel and a weighted average sold put price of $45.00 per barrel. The contracts are indexed to Dated Brent prices.

At September 30, 2017, our open commodity derivative instruments were in a net asset position of $1.6 million. As of September 30, 2017, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $54.7 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $47.3 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, 2017, we had indebtedness outstanding under the Facility of $600.0 million, of which $400.0 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, 2017 was approximately 4.5%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.5 million in interest expense per year on the Facility. We pay commitment fees on the undrawn availability and unavailable commitments under the Facility and on the undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.

As of September 30, 2017, the fair market value of our interest rate swaps was a net asset of approximately $0.7 million. If LIBOR changed by 10%, it would have a negligible impact on the fair market value of our interest rate swaps.

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, 2017, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

There have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.

Item 1A. Risk Factors

There have been no material changes from the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2016 and in the "Item 1A. Risk Factors" section of our quarterly report on Form 10-Q for the quarter ended June 30, 2017.

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, 2017 and the average price paid per share.



	Total Number	Average
	of Shares	Price Paid
	Purchased	per Share
	(In thousands)
January 1, 2017—January 31, 2017	74	$	7.01
February 1, 2017—February 28, 2017	—	—
March 1, 2017—March 31, 2017	—	—
April 1, 2017—April 30, 2017	—	—
May 1, 2017—May 31, 2017	—	—
June 1, 2017—June 30, 2017	13	6.12
July 1, 2017—July 31, 2017	—	—
August 1, 2017—August 31, 2017	—	—
September 1, 2017—September 30, 2017	—	—
Total	87	6.87


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable.

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Item 5.	Other Information.

There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K, other than as follows:

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

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

We are not presently aware that we and our consolidated subsidiaries have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the fiscal quarter ended September 30, 2017. In addition, except as described below, at the time of filing this quarterly report on Form 10-Q, we are not aware of any such reportable 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, 2017, as the case may be, additional reportable transactions may be disclosed by such companies.

As of September 30, 2017, funds affiliated with Warburg Pincus (“Warburg Pincus”) held approximately 24% of our outstanding common shares. We are also a party to a shareholders agreement with Warburg Pincus pursuant to which, among other things, Warburg Pincus currently has the right to designate two members of our board of directors. Accordingly, Warburg Pincus may be deemed an “affiliate” of us, both currently and during the fiscal quarter ended September 30, 2017.

Disclosure relating to Warburg Pincus and its affiliates

Warburg Pincus informed us of the information reproduced below (the “SAMIH Disclosure”) regarding Santander Asset Management Investment Holdings Limited (“SAMIH”). SAMIH is a company that may be considered an affiliate of Warburg Pincus. Because we and SAMIH may be deemed to be controlled by Warburg Pincus, we may be considered an “affiliate” of SAMIH for the purposes of Section 13(r) of the Exchange Act.

SAMIH Disclosure:

Quarter ended September 30, 2017

Santander UK plc (“Santander UK”) holds two savings accounts and one current account for two customers resident in the United Kingdom (“UK”) who are currently designated by the United States (“US”) under the Specially Designated Global Terrorist (“SDGT”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine month period ended September 30, 2017 were negligible relative to the overall revenues and profits of Banco Santander SA.

Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the nine month period ended September 30, 2017. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. No revenues or profits were generated by Santander UK on this account in the nine month period ended September 30, 2017.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10‑Q.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		Kosmos Energy Ltd.
		(Registrant)

Date	November 6, 2017	/s/ THOMAS P. CHAMBERS
		Thomas P. Chambers
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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INDEX OF EXHIBITS



Exhibit Number		Description of Document
10.1**		Farm-out Agreement Relating to Block C-18, Offshore Mauritania between Tullow Mauritania Limited, Kosmos Energy Mauritania and BP Mauritania Investments Limited dated June 9, 2017.

10.2**		Deed of Novation and Amendment dated September 20, 2017 between Tullow Mauritania Limited, Total E&P Mauritania Block C18 B.V., Kosmos Energy Mauritania, BP Mauritania Investments Limited and SMHPM in related to Block C-18.

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

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* Filed herewith.

** Furnished herewith.