SEC Filing | Kosmos Energy

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kos-20210930

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, 2021


☐			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)


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

8176 Park Lane
Dallas,	Texas	75231
(Address of principal executive offices)		(Zip Code)

Title of each class

Trading Symbol

Name of each exchange on which registered:

Common Stock $0.01 par value

KOS

New York Stock Exchange

London Stock Exchange

Registrant’s telephone number, including area code: +1 214 445 9600

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 4, 2021
Common Shares, $0.01 par value						451,889,062

Table of Contents

TABLE OF CONTENTS

Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its wholly owned 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			7
Consolidated Statements of Operations			8
Consolidated Statements of Stockholders’ Equity			9
Consolidated Statements of Cash Flows			10
Notes to Consolidated Financial Statements			11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
Item 3. Quantitative and Qualitative Disclosures about Market Risk			47
Item 4. Controls and Procedures			49

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			49
Item 1A. Risk Factors			49
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			49
Item 3. Defaults Upon Senior Securities			50
Item 4. Mine Safety Disclosures			50
Item 5. Other Information			50
Item 6. Exhibits			50
Signatures			51
Index to Exhibits			52

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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.
“ANP-STP”						Agencia Nacional Do Petroleo De Sao Tome E Principe.
“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.
“Asset Coverage Ratio”						The “Asset Coverage Ratio” as defined in the GoM Term Loan means, as of each March 31, June 30, September 30 and December 31 of each Fiscal Year, commencing December 31, 2020, the ratio of (a) Total PDP PV-10 (as defined in the GoM Term Loan) as of such date to (b) outstanding principal amount of Loans (as defined in the GoM Term Loan) as of such date.
“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.
“BOEM”						Bureau of Ocean Energy Management.
“Boepd”						Barrels of oil equivalent per day.
“Bopd”						Barrels of oil per day.
“BP”						BP p.l.c. and related subsidiaries.
“Bwpd”						Barrels of water per day.
“Corporate Revolver”						Revolving Credit Facility Agreement dated November 23, 2012 (as amended or as amended and restated from time to time).
“COVID-19”						Coronavirus disease 2019.
“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.
“DST”						Drill stem test.
“Dry hole” or “Unsuccessful well”						A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
“DT”						Deepwater Tano.

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“EBITDAX”						Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.
“ESG”						Environmental, social, and governance.
“ESP”						Electric submersible pump.
“E&P”						Exploration and production.
“Facility”						Facility agreement dated March 28, 2011 (as amended or as amended and restated from time to time).
“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/or for taking on a portion of future costs 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 future costs and/or other work as a condition of the assignment.
“FEED”						Front End Engineering Design.
“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 and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
“FLNG”						Floating liquefied natural gas.
“FPS”						Floating production system.
“FPSO”						Floating production, storage and offloading vessel.
“GAAP”						Generally Accepted Accounting Principles in the United States of America.
“GEPetrol”						Guinea Equatorial De Petroleos.
“GHG”						Greenhouse gas.
“GJFFDP”						Greater Jubilee Full Field Development Plan.
“GNPC”						Ghana National Petroleum Corporation.
“GoM Term Loan”						Senior Secured Term Loan Credit Agreement dated September 30, 2020.
“Greater Tortue Ahmeyim”						Ahmeyim and Guembeul discoveries.
“GTA UUOA”						Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
“HLS”						Heavy Louisiana Sweet.
“H&M”						Hull and Machinery insurance.
“Jubilee UUOA”						Unitization and Unit Operating Agreement covering the Jubilee Unit.
“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.
“LNG”						Liquefied natural gas.
“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 Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
“LSE”						London Stock Exchange.
“LTIP”						Long Term Incentive Plan.
“MBbl”						Thousand barrels of oil.

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“MBoe”						Thousand barrels of oil equivalent.
“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.
“MMBtu”						Million British thermal units.
“MMcf”						Million cubic feet of natural gas.
“MMcfd”						Million cubic feet per day of natural gas.
“MMTPA”						Million metric tonnes per annum.
“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.
“NYSE”						New York Stock Exchange.
“Ophir”						Ophir Energy plc.
“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.
“RSC”						Ryder Scott Company, L.P.
“SEC”						Securities and Exchange Commission.
“7.125% Senior Notes”						7.125% Senior Notes due 2026.
“7.500% Senior Notes”						7.500% Senior Notes due 2028.
“Shelf margin”						The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
“Shell”						Royal Dutch Shell and related subsidiaries.
“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 gas in the strata.

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“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.
“TAG GSA”						TEN Associated Gas - Gas Sales Agreement.
“TEN”						Tweneboa, Enyenra and Ntomme.
“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.
“Tortue Phase 1 SPA”						Greater Tortue Ahmeyim Agreement for a Long Term Sale and Purchase of LNG.
“Trafigura”						Trafigura Group PTD, Ltd. and related subsidiaries including Trafigura Trading LLC.
“Trap”						A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
“Trident”						Trident Energy.
“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.
“WCTP”						West Cape Three Points.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30, 2021		December 31, 2020
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	111,329	$	149,027
Restricted cash	43,208		195
Receivables:
Joint interest billings, net	26,147		26,002
Oil sales	31,740		44,491

Other	17,970		8,320
Inventories	152,950		128,972
Prepaid expenses and other	32,577		27,870
Derivatives	—		15,414
Total current assets	415,921		400,291
Property and equipment:
Oil and gas properties, net	3,435,384		3,310,276
Other property, net	7,513		10,637
Property and equipment, net	3,442,897		3,320,913
Other assets:

Restricted cash	305		542
Long-term receivables	271,295		117,497
Deferred financing costs, net of accumulated amortization of $19,258 and $17,296 at September 30, 2021 and December 31, 2020, respectively	1,744		3,706

Derivatives	—		964
Other	21,562		23,680
Total assets	$	4,153,724	$	3,867,593
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	143,155	$	221,430
Accrued liabilities	180,725		203,260
Current maturities of long-term debt	30,000		7,500
Derivatives	107,863		28,009
Total current liabilities	461,743		460,199
Long-term liabilities:
Long-term debt, net	2,368,240		2,103,931
Derivatives	21,548		8,069
Asset retirement obligations	265,409		244,166
Deferred tax liabilities	505,253		573,619
Other long-term liabilities	244,779		37,455
Total long-term liabilities	3,405,229		2,967,240
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2021 and December 31, 2020	—		—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 453,004,504 and 449,718,317 issued at September 30, 2021 and December 31, 2020, respectively	4,530		4,497
Additional paid-in capital	2,330,337		2,307,220
Accumulated deficit	(1,811,108)		(1,634,556)
Treasury stock, at cost, 44,263,269 shares at September 30, 2021 and December 31, 2020, respectively	(237,007)		(237,007)
Total stockholders’ equity	286,752		440,154
Total liabilities and stockholders’ equity	$	4,153,724	$	3,867,593

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,
	2021		2020		2021		2020
Revenues and other income:
Oil and gas revenue	$	198,936	$	224,786	$	759,455	$	529,880
Gain on sale of assets	1,538		—		1,564		—
Other income, net	66		1		210		2
Total revenues and other income	200,540		224,787		761,229		529,882
Costs and expenses:
Oil and gas production	50,316		84,277		211,871		234,627
Facilities insurance modifications, net	1,554		2,465		3,495		10,555
Exploration expenses	23,982		13,977		41,452		74,293
General and administrative	22,459		18,269		66,628		57,366
Depletion, depreciation and amortization	64,914		111,231		292,616		326,390
Impairment of long-lived assets	—		—		—		150,820
Interest and other financing costs, net	26,873		27,068		90,727		83,177
Derivatives, net	38,224		1,187		252,606		(34,776)
Other expenses, net	194		2,805		1,003		27,962
Total costs and expenses	228,516		261,279		960,398		930,414
Loss before income taxes	(27,976)		(36,492)		(199,169)		(400,532)
Income tax expense (benefit)	621		892		(22,617)		19,010
Net loss	$	(28,597)	$	(37,384)	$	(176,552)	$	(419,542)

Net loss per share:
Basic	$	(0.07)	$	(0.09)	$	(0.43)	$	(1.04)
Diluted	$	(0.07)	$	(0.09)	$	(0.43)	$	(1.04)

Weighted average number of shares used to compute net loss per share:
Basic	408,520		405,409		408,009		405,131
Diluted	408,520		405,409		408,009		405,131

Dividends declared per common share	$	—	$	—	$	—	$	0.0452

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)


				Additional
	Common Shares			Paid-in		Accumulated		Treasury
	Shares	Amount		Capital		Deficit		Stock		Total
2021:
Balance as of December 31, 2020	449,718	$	4,497	$	2,307,220	$	(1,634,556)	$	(237,007)	$	440,154
Dividends	—	—		90		—		—		90
Equity-based compensation	—	—		8,327		—		—		8,327
Restricted stock units	2,408	24		(24)		—		—		—
Tax withholdings on restricted stock units	—	—		(1,018)		—		—		(1,018)
Net loss	—	—		—		(90,768)		—		(90,768)
Balance as of March 31, 2021	452,126	4,521		2,314,595		(1,725,324)		(237,007)		356,785
Dividends	—	—		29		—		—		29
Equity-based compensation	—	—		7,634		—		—		7,634
Restricted stock units	540	6		(6)		—		—		—
Tax withholdings on restricted stock units	—	—		(19)		—		—		(19)
Net loss	—	—		—		(57,187)		—		(57,187)
Balance as of June 30, 2021	452,666	4,527		2,322,233		(1,782,511)		(237,007)		307,242
Dividends	—	—		21		—		—		21
Equity-based compensation	—	—		8,149		—		—		8,149
Restricted stock units	339	3		(3)		—		—		—
Tax withholdings on restricted stock units	—	—		(63)		—		—		(63)
Net loss	—	—		—		(28,597)		—		(28,597)
Balance as of September 30, 2021	453,005	$	4,530	$	2,330,337	$	(1,811,108)	$	(237,007)	$	286,752

2020:
Balance as of December 31, 2019	445,779	$	4,458	$	2,297,221	$	(1,222,970)	$	(237,007)	$	841,702
Dividends ($0.0452 per share)	—	—		(18,918)		—		—		(18,918)
Equity-based compensation	—	—		10,078		—		—		10,078
Restricted stock units	3,590	36		(36)		—		—		—
Tax withholdings on restricted stock units	—	—		(4,947)		—		—		(4,947)
Net loss	—	—		—		(182,767)		—		(182,767)
Balance as of March 31, 2020	449,369	4,494		2,283,398		(1,405,737)		(237,007)		645,148
Dividends	—	—		24		—		—		24
Equity-based compensation	—	—		8,406		—		—		8,406
Restricted stock awards and units	206	2		(2)		—		—		—
Net loss	—	—		—		(199,391)		—		(199,391)
Balance as of June 30, 2020	449,575	4,496		2,291,826		(1,605,128)		(237,007)		454,187
Dividends	—	—		27		—		—		27
Equity-based compensation	—	—		8,734		—		—		8,734
Restricted stock awards and units	98	1		(1)		—		—		—
Net loss	—	—		—		(37,384)		—		(37,384)
Balance as of September 30, 2020	449,673	$	4,497	$	2,300,586	$	(1,642,512)	$	(237,007)	$	425,564

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2021		2020
Operating activities
Net loss	$	(176,552)	$	(419,542)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	300,404		333,120
Deferred income taxes	(68,366)		3,715
Unsuccessful well costs and leasehold impairments	16,772		24,338
Impairment of long-lived assets	—		150,820
Change in fair value of derivatives	259,289		(32,156)
Cash settlements on derivatives, net (including $(142.9) million and $22.8 million on commodity hedges during 2021 and 2020)	(150,255)		16,904
Equity-based compensation	24,011		26,392
Gain on sale of assets	(1,564)		—
Loss on extinguishment of debt	15,223		2,893
Other	(2,763)		6,673
Changes in assets and liabilities:
Decrease in receivables	1,537		88,107
Increase in inventories	(24,280)		(30,848)
(Increase) decrease in prepaid expenses and other	(4,800)		3,253
Decrease in accounts payable	(35,545)		(2,631)
Decrease in accrued liabilities	(9,270)		(150,381)
Net cash provided by operating activities	143,841		20,657
Investing activities
Oil and gas assets	(377,125)		(215,425)
Other property	(725)		(1,838)


Proceeds on sale of assets	5,327		1,713
Notes receivable from partners	(41,712)		(53,574)
Net cash used in investing activities	(414,235)		(269,124)
Financing activities
Borrowings under long-term debt	250,000		300,000
Payments on long-term debt	(400,000)		—
Advances under production prepayment agreement	—		50,000
Net proceeds from issuance of senior notes	444,375		—

Tax withholdings on restricted stock units	(1,100)		(4,947)
Dividends	(512)		(19,174)
Deferred financing costs	(17,291)		(4,570)
Net cash provided by financing activities	275,472		321,309
Net increase in cash, cash equivalents and restricted cash	5,078		72,842
Cash, cash equivalents and restricted cash at beginning of period	149,764		229,346
Cash, cash equivalents and restricted cash at end of period	$	154,842	$	302,188

Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest	$	61,046	$	101,908
Income taxes, net of refund received	$	67,581	$	68,330
Non-cash activity:
Production Prepayment Agreement converted to GoM Term Loan	$	—	$	50,000

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Kosmos Energy Ltd. was originally incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware in December 2018 and transferred all of our equity interests in Kosmos Energy Holdings to a new, wholly-owned subsidiary, Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. 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 full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration program in Equatorial Guinea, Ghana and U.S. Gulf of Mexico. Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.

Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations in four geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and U.S. Gulf of Mexico.

2. Accounting Policies

General

The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. 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 interim consolidated financial statements were prepared in accordance with the requirements of the SEC for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by GAAP have been condensed or omitted from these interim consolidated financial statements. These interim consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2020, included in our annual report on Form 10-K.

Reclassifications

Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no significant impact on our reported net loss, current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows.

Cash, Cash Equivalents and Restricted Cash


	September 30, 2021		December 31, 2020
	(In thousands)
Cash and cash equivalents	$	111,329	$	149,027
Restricted cash - current	43,208		195
Restricted cash - long-term	305		542
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	154,842	$	149,764

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. When our net leverage ratio exceeds 2.50x, we are required under the

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Facility 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 7.125% Senior Notes and the 7.500% Senior Notes plus the Corporate Revolver or the Facility, whichever is greater. As of September 30, 2021 we have restricted cash of approximately $42.9 million to meet our requirements.

In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. Certain of 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 respective 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.

Inventories

Inventories consisted of $127.9 million and $127.5 million of materials and supplies and $25.1 million and $1.5 million of hydrocarbons as of September 30, 2021 and December 31, 2020, 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.

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.

Revenue Recognition

Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.

Oil and gas revenue is composed of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	34,247	$	43,003	$	145,378	$	95,520
Revenues from contract with customer - Ghana	65,969		124,436		321,855		238,686
Revenues from contract with customers - U.S. Gulf of Mexico	96,626		55,620		298,905		198,294
Provisional oil sales contracts	2,094		1,727		(6,683)		(2,620)
Oil and gas revenue	$	198,936	$	224,786	$	759,455	$	529,880

Concentration of Credit Risk

Our revenue can be materially affected by current economic conditions and the price of oil and natural gas. However, based on the current demand for crude oil and natural gas and the fact that alternative purchasers are available, we believe that the loss of our marketing agents and/or any of the purchasers identified by our marketing agents would not have a long‑term material adverse effect on our financial position or results of operations. The continued economic disruption resulting from the COVID-19 pandemic could materially impact the Company’s business in future periods. Any potential disruption will depend on the duration and intensity of these events, which are highly uncertain and cannot be predicted at this time.

Recent Accounting Standards

In December 2019, the FASB issued ASU 2019-12, “Simplifying the Accounting for Income Taxes”. Our adoption of ASU 2019-12 on January 1, 2021, did not have a material impact on our income tax expense.

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3. Acquisitions and Divestitures

During the third quarter of 2020, Kosmos entered into an agreement with Shell to farm down interests in a portfolio of frontier exploration assets for cash consideration of $96.0 million and future contingent consideration of up to $100.0 million. Under the terms of the agreement, Shell acquired Kosmos' participating interest in blocks offshore Sao Tome and Principe, (excluding Block 5 offshore Sao Tome and Principe), Suriname, Namibia, and South Africa. Kosmos received proceeds totaling $95.0 million during the fourth quarter of 2020 resulting in gain on sale of assets of $92.1 million. The remaining proceeds of $1.0 million related to Kosmos' participating interest in South Africa were received during the third quarter of 2021. The future contingent consideration is payable by Shell upon approval of the relevant operating committee of an appraisal plan for submission to the relevant governmental authority for any of the first four exploration wells it elects to drill in the purchased assets, excluding South Africa. Shell will pay us $50.0 million for each appraisal plan approved by the relevant operating committee to be submitted, subject to an aggregate cap of $100.0 million, or two $50.0 million payments.

4. Joint Interest Billings and Long-term Receivables

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 for shared costs. 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 Ghana, the foreign contractor group funded GNPC’s 5% share of the TEN development costs. The foreign contractor group is being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of September 30, 2021 and December 31, 2020, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $5.8 million and $5.8 million, respectively, and the long-term portions were $21.6 million and $21.2 million, respectively.

Notes Receivables

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal obligating us separately to finance the respective national oil company’s share of certain development costs incurred through first gas production for Greater Tortue Ahmeyim Phase 1, currently projected in the third quarter of 2023. Kosmos’ share for the two agreements combined is up to $239.7 million, which is to be repaid with interest through the national oil companies’ share of future revenues. As of September 30, 2021 and December 31, 2020, the balance due from the national oil companies was $143.4 million and $96.3 million, respectively, which is classified as Long-term receivables on our consolidated balance sheets.

Other Long-term Receivables

In August 2021, BP, as the operator of the Greater Tortue project (“BP Operator”), with the consent of the Greater Tortue Unit participants and the respective States, agreed to sell the Greater Tortue FPSO (which is currently under construction by Technip Energies in China) to an affiliate of BP (“BP Buyer”). The Greater Tortue FPSO will be leased back to BP Operator under a long-term lease agreement, for exclusive use in the Greater Tortue project. BP Operator will continue to manage and supervise the construction contract with Technip Energies. Delivery of the Greater Tortue FPSO to BP Buyer will occur after construction is complete and the Greater Tortue FPSO has been commissioned, with the lease to BP Operator becoming effective on the same date, currently estimated to be in the third quarter of 2023.

As a result of the above transactions entered into by BP Operator, Kosmos has recognized a Long-term receivable of $200.2 million from BP Operator for our share of the consideration paid from BP Buyer to and held by BP Operator as well as a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Tortue FPSO. This Long-term receivable will be non-cash settled against future obligations payable to BP Operator. During the third quarter of 2021, BP Operator settled our payment obligations of $51.2 million of capital expenditures and $42.7 million of existing Accounts Payable to BP Operator, these non-cash impacts are excluded from the statement of cash flows.

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5. Property and Equipment

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


	September 30, 2021		December 31, 2020
	(In thousands)
Oil and gas properties:
Proved properties	$	5,751,720	$	5,369,737
Unproved properties	515,499		495,390
Total oil and gas properties	6,267,219		5,865,127
Accumulated depletion	(2,831,835)		(2,554,851)
Oil and gas properties, net	3,435,384		3,310,276

Other property	58,541		59,949
Accumulated depreciation	(51,028)		(49,312)
Other property, net	7,513		10,637

Property and equipment, net	$	3,442,897	$	3,320,913

We recorded depletion expense of $58.8 million and $104.9 million for the three months ended September 30, 2021 and 2020, respectively, and $274.6 million and $307.8 million for the nine months ended September 30, 2021 and 2020, respectively. During the three months ended September 30, 2021 and 2020, no oil and gas asset impairments were recorded. During the nine months ended September 30, 2021 and 2020, we recorded asset impairments totaling zero and $150.8 million, respectively, in our consolidated statement of operations in connection with fair value assessments for oil and gas proved properties.

6. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the nine months ended September 30, 2021.


	September 30, 2021
	(In thousands)
Beginning balance	$	186,289
Additions to capitalized exploratory well costs pending the determination of proved reserves	20,257
Reclassification due to determination of proved reserves	(201)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	206,345

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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, 2021		December 31, 2020
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	11,393	$	—
Exploratory well costs capitalized for a period of one to two years	30,684		28,692
Exploratory well costs capitalized for a period of three to five years	164,268		157,597
Ending balance	$	206,345	$	186,289
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	3		3

As of September 30, 2021, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania, the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal, and the Asam discovery in Block S offshore Equatorial Guinea.

BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well in the northern part of Block C8 offshore Mauritania, which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made. During the fourth quarter of 2019, we completed the nearby Orca-1 exploration well which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality is expected to be made. The BirAllah and Orca discoveries are being analyzed as a joint development including concept design and other appraisal studies.

Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted to the government of Senegal. In September 2019, we completed the Yakaar-2 appraisal well which encountered hydrocarbon pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well. Following additional evaluation, a decision regarding commerciality is expected to be made. The Yakaar and Teranga discoveries are being analyzed as a joint development including concept design and other appraisal studies.

Asam Discovery — In October 2019, we completed the S-5 exploration well offshore Equatorial Guinea, which encountered hydrocarbon pay. In July 2020, an appraisal plan was approved by the government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and work is currently ongoing to integrate all available data into models to establish the scale of the discovered resource. Additionally, engineering is progressing concepts around required subsea infrastructure necessary for a subsea tieback. Once the appraisal plan involving this work is complete, a decision regarding commerciality will be made.

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7. Debt


	September 30, 2021		December 31, 2020
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,150,000	$	1,200,000
Corporate Revolver	—		100,000
7.125% Senior Notes	650,000		650,000
7.500% Senior Notes	450,000		—
GoM Term Loan	200,000		200,000
Total	2,450,000		2,150,000
Unamortized deferred financing costs and discounts	(51,760)		(38,569)
Total debt, net	2,398,240		2,111,431
Less: Current maturities of long-term debt	(30,000)		(7,500)
Long-term debt, net	$	2,368,240	$	2,103,931

__________________________________

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of September 30, 2021, borrowings under the Facility totaled $1.15 billion and the undrawn availability under the facility was $85.2 million (limited by current commitments). In May 2021, the Company entered into an amended and restated facility agreement and certain ancillary documents. The amendments to the terms of the Facility included the following:

•the extension of the maturity date by two years (final maturity date now occurs on March 31, 2027),

•the extension of the amortization schedule such that amortization of principal is to commence on March 31, 2024 and continue in equal amounts every six months thereafter until the maturity date,

•an increase in the interest margin by 0.5% (applicable interest margin for the first three years is now LIBOR +3.75%),

•the incorporation of a mechanism for two ESG key performance indicators (“KPIs”) to impact the interest margin either positively or negatively based upon delivering emissions targets and achieving certain third party ESG ratings,

•an increase in the Loan Life Coverage Ratio from 1.10x to 1.30x after March 31, 2024,

•the removal of Kosmos Energy Investments Senegal Limited, Kosmos Energy Senegal and Kosmos Energy Mauritania as borrowers, guarantors and pledged subsidiaries, and

•a reduction in the Facility size to $1.25 billion (from $1.5 billion).

As amended, the Facility has an available borrowing base of approximately $1.24 billion. As part of the amendment, the Company incurred $15.2 million for loss on extinguishment of debt during the second quarter of 2021. The Facility amendment contains other customary representations and warranties, covenants and informational undertakings, in each case, subject to certain exceptions and conditions. The Facility amendment also provides for certain customary events of default, including, among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults to certain indebtedness, certain events of insolvency, judgment defaults, and repudiation or rescission of certain documents supporting the amendment. If such an event of default occurs, the agents under such amendment are entitled to take various actions, including the cancellation of any outstanding commitments, acceleration of amounts due thereunder and taking certain permitted enforcement actions under the ancillary security documents, subject in each case to the terms of the Facility amendment and such security documents. During the September 2021 redetermination, the Company’s lending syndicate approved a borrowing base capacity in excess of the facility size of $1.25 billion.

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When our net leverage ratio exceeds 2.50x, we are required under the Facility 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 7.125% Senior Notes and the 7.500% Senior Notes plus the Corporate Revolver or the Facility, whichever is greater. As of September 30, 2021 we have restricted cash of approximately $42.9 million to meet our requirements.

As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, in July 2020, we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation through December 31, 2021. The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. We were in compliance with the financial covenants as of the most recent assessment date. The Facility, as amended, contains customary cross default provisions.

Corporate Revolver

In August 2018, we amended and restated the Corporate Revolver maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin to 5%. This results in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of September 30, 2021, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $400.0 million.

As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, in July 2020, we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation through December 31, 2021. The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. We were in compliance with the financial covenants as of the most recent assessment date. The Corporate Revolver contains customary cross default provisions.

7.125% Senior Notes due 2026

In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of approximately $640.0 million after deducting fees and other expenses. We used the net proceeds to redeem all of the previously issued 7.875% Senior Secured Notes due 2021, repay a portion of the outstanding indebtedness under the Corporate Revolver and pay fees and expenses related to the redemption, repayment and the issuance of the 7.125% Senior Notes.

The 7.125% Senior Notes mature on April 4, 2026. Interest is payable in arrears each April 4 and October 4, commencing on October 4, 2019. The 7.125% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.125% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that guarantee the Facility. We were in compliance with the financial covenants contained in the 7.125% Senior Notes as of September 30, 2021. The 7.125% Senior Notes contain customary cross default provisions.

7.500% Senior Notes due 2028

In March 2021, the Company issued $450.0 million of 7.500% Senior Notes and received net proceeds of approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general corporate purposes.

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Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and, on a subordinated basis, guarantee the Corporate Revolver and the 7.125% Senior Notes.

At any time prior to March 1, 2024, and subject to certain conditions, the Company may, on one or more occasions, redeem up to 40% of the original principal amount of the 7.500% Senior Notes with an amount not to exceed the net cash proceeds of certain equity offerings at a redemption price of 107.500% of the outstanding principal amount of the 7.500% Senior Notes, together with accrued and unpaid interest and premium, if any, to, but excluding, the date of redemption. Additionally, at any time prior to March 1, 2024 the Company may, on any one or more occasions, redeem all or a part of the 7.500% Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a “make-whole” premium. On or after March 1, 2024, the Company may redeem all or a part of the 7.500% Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:


Year	Percentage
On or after March 1, 2024, but before February 28, 2025	103.750	%
On or after March 1, 2025, but before February 28, 2026	101.875	%
On or after March 1, 2026 and thereafter	100.000	%

We may also redeem the 7.500% Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the 7.500% Senior Notes at a price equal to the principal amount of the 7.500% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the 7.500% Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

Upon the occurrence of a change of control triggering event as defined under the 7.500% Senior Notes indenture, the Company will be required to make an offer to repurchase the 7.500% Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

If we sell assets, under certain circumstances outlined in the 7.500% Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the 7.500% Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the 7.500% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

The 7.500% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. Certain of these covenants will be terminated if the 7.500% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred. We were in compliance with the financial covenants contained in the 7.500% Senior Notes as of September 30, 2021. The 7.500% Senior Notes contain customary cross default provisions.

Production Prepayment Agreement

In June 2020, the Company received $50.0 million from Trafigura under a Production Prepayment Agreement of crude oil sales related to a portion of our U.S. Gulf of Mexico production primarily in 2022 and 2023. The Company terminated the Production Prepayment Agreement and the initial prepayment of $50.0 million advanced under the Production Prepayment Agreement by Trafigura in the second quarter of 2020 was extinguished and converted into the GoM Term Loan as of September 30, 2020.

GoM Term Loan

In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to $100.0 million subject to certain conditions. The GoM Term Loan bears interest at an effective rate of approximately 6% per annum and matures in 2025, with principal repayments beginning in the fourth quarter of 2021. We were in compliance with the covenants, representations and warranties contained in the GoM Term Loan as of as of September 30, 2021 (the most recent

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assessment date). The GoM Term Loan contains customary cross default provisions as well as maturity acceleration provisions if certain Permitted Guaranteed Facilities are not refinanced prior to scheduled maturity.

Principal Debt Repayments

At September 30, 2021, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:


	Payments Due by Year
	Total		2021(2)		2022		2023		2024		2025		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,450,000	$	7,500	$	30,000	$	142,621	$	237,834	$	402,692	$	1,629,353

__________________________________

(1)Includes the scheduled principal maturities for the $650.0 million aggregate principal amount of the 7.125% Senior Notes, the $450.0 million aggregate principal amount of the 7.500% Senior Notes and borrowings under the Facility, Corporate Revolver and GoM Term Loan. The scheduled maturities of debt related to the Facility as of September 30, 2021 are based on 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.

(2)Represents payments for the period October 1, 2021 through December 31, 2021.

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,
	2021		2020		2021		2020
	(In thousands)
Interest expense	$	36,055	$	29,760	$	103,229	$	90,031
Amortization—deferred financing costs	2,597		2,255		7,788		6,730
Loss on extinguishment of debt	—		678		15,223		2,893
Capitalized interest	(12,252)		(5,806)		(31,956)		(18,062)
Deferred interest	(600)		531		(724)		2,028
Interest income	(2,237)		(1,269)		(8,309)		(3,371)
Other, net	3,310		919		5,476		2,928
Interest and other financing costs, net	$	26,873	$	27,068	$	90,727	$	83,177

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 Measurement.

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Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of September 30, 2021. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.


				Weighted Average Price per Bbl
				Net Deferred
				Premium
				Payable/				Sold
Term	Type of Contract	Index	MBbl	(Receivable)		Swap		Put		Floor		Ceiling
2021:
Oct — Dec	Swaps with sold puts	Dated Brent	1,500	$	—	$	53.96	$	42.92	$	—	$	—
Oct — Dec	Three-way collars	Dated Brent	750	0.45		—		32.50		40.00		53.47
Oct — Dec	Three-way collars	NYMEX WTI	250	1.00		—		37.50		45.00		55.00
Oct — Dec	Sold calls(1)	Dated Brent	1,750	—		—		—		—		70.09
2022:
Jan — Dec	Three-way collars	Dated Brent	4,500	0.64		—		43.33		56.67		76.91
Jan — Dec	Two-way collars	Dated Brent	3,000	1.26		—		—		55.00		76.67
Jan — Dec	Sold calls(1)	Dated Brent	1,581	—		—		—		—		60.00

__________________________________

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

In October 2021, we entered into Dated Brent two-way collar contracts for 2.0 MMBbl from January 2022 through December 2022 with a floor price of $70.00 per barrel and a ceiling price of $90.00 per barrel.

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The following tables disclose the Company’s derivative instruments as of September 30, 2021 and December 31, 2020, and gain/(loss) from derivatives during the three and nine months ended September 30, 2021 and 2020, respectively:


		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2021		December 31, 2020
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity	Derivatives assets—current	$	—	$	15,414
Provisional oil sales	Receivables: Oil Sales	—		(677)
Commodity	Derivatives assets—long-term	—		964
Derivative liabilities:
Commodity	Derivatives liabilities—current	(107,863)		(28,009)
Commodity	Derivatives liabilities—long-term	(21,548)		(8,069)
Total derivatives not designated as hedging instruments		$	(129,411)	$	(20,377)


		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)	2021		2020		2021		2020
		(In thousands)
Derivatives not designated as hedging instruments:
Provisional oil sales	Oil and gas revenue	$	2,094	$	1,727	$	(6,683)	$	(2,620)
Commodity	Derivatives, net	(38,224)		(1,187)		(252,606)		34,776
Total derivatives not designated as hedging instruments		$	(36,130)	$	540	$	(259,289)	$	32,156

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, 2021 and December 31, 2020, 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 820 — Fair Value Measurement, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:

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

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

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

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2021 and December 31, 2020, 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, 2021
Assets:
Commodity derivatives	$	—	$	—	$	—	$	—
Provisional oil sales	—		—		—		—

Liabilities:
Commodity derivatives	—		(129,411)		—		(129,411)

Total	$	—	$	(129,411)	$	—	$	(129,411)
December 31, 2020
Assets:
Commodity derivatives	$	—	$	16,378	$	—	$	16,378
Provisional oil sales	—		(677)		—		(677)

Liabilities:
Commodity derivatives	—		(36,078)		—		(36,078)

Total	$	—	$	(20,377)	$	—	$	(20,377)

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 credit losses, 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 collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent, NYMEX WTI, or Argus LLS oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (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 the respective index. 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 provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date.

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Debt

The following table presents the carrying values and fair values at September 30, 2021 and December 31, 2020:


	September 30, 2021				December 31, 2020
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
7.125% Senior Notes	$	644,302	$	637,728	$	643,524	$	613,412
7.500% Senior Notes	444,732		436,905		—		—
GoM Term Loan	200,000		200,000		200,000		200,000
Corporate Revolver	—		—		100,000		100,000
Facility	1,150,000		1,150,000		1,200,000		1,200,000
Total	$	2,439,034	$	2,424,633	$	2,143,524	$	2,113,412

The carrying values of our 7.125% Senior Notes and 7.500% Senior Notes represent the principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes and 7.500% Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying values of the GoM Term Loan, Corporate Revolver and Facility approximate fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods.

Nonrecurring Fair Value Measurements - Long-lived assets

Certain long-lived assets are reported at fair value on a non-recurring basis on the Company's consolidated balance sheet. These long-lived assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Our long-lived assets are reviewed for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

The Company calculates the estimated fair values of its long-lived assets using the income approach described in the ASC 820 — Fair Value Measurements. Significant inputs associated with the calculation of estimated discounted future net cash flows include anticipated future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These are classified as Level 3 fair value assumptions. The Company utilizes an average of third-party industry forecasts of Dated Brent, adjusted for location and quality differentials, to determine our pricing assumptions. In order to evaluate the sensitivity of the assumptions, we analyze sensitivities to prices, production, and risk adjustment factors.

As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, we reviewed our long-lived assets for impairment at March 31, 2020, which resulted in impairment charges of $150.8 million, reducing the carrying value of the properties to their estimated fair values of $243.7 million. During the fourth quarter of 2020 the Company recorded additional impairment charges totaling approximately $3.2 million resulting in impairment charges totaling $154.0 million for the year ended December 31, 2020. During the three and nine months ended September 30, 2021, the Company did not recognize impairment of proved oil and gas properties as no impairment indicators were identified. If we experience further declines in oil pricing expectations, increases in our estimated future expenditures or a decrease in our estimated production profile, our long-lived assets could be at risk of additional impairment.

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10. Equity-based Compensation

Restricted Stock Units

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $8.1 million and $8.7 million during the three months ended September 30, 2021 and 2020, respectively, and $24.0 million and $26.4 million during the nine months ended September 30, 2021 and 2020, respectively. The total tax benefit for the three months ended September 30, 2021 and 2020 was $1.5 million and $1.8 million, respectively, and $4.5 million and $5.6 million during the nine months ended September 30, 2021 and 2020, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $1.5 million and $0.1 million for the three months ended September 30, 2021 and 2020, respectively, and $6.3 million and $1.2 million during the nine months ended September 30, 2021 and 2020, respectively. The fair value of awards vested during the three months ended September 30, 2021 and 2020 was $1.0 million and $0.2 million, respectively, and $9.4 million and $26.0 million during the nine months ended September 30, 2021 and 2020, respectively. The Company granted restricted stock units with service vesting criteria and a combination of market and service vesting criteria under the LTIP. Substantially all of these grants vest over three years. Upon vesting, restricted stock units become issued and outstanding stock.

The following table reflects the outstanding restricted stock units as of September 30, 2021:


		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, 2020	4,840	$	5.34	7,859	$	8.11
Granted(1)	2,856	2.56		6,727	3.91
Forfeited(1)	(524)	4.05		(1,918)	5.47
Vested	(2,379)	5.18		(1,371)	9.95
Outstanding at September 30, 2021	4,793	3.90		11,297	5.29

__________________________________

(1)The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.

As of September 30, 2021, total equity-based compensation to be recognized on unvested restricted stock units is $27.3 million over a weighted average period of 1.71 years. In April 2021, the board of directors approved an amendment to the LTIP to add 11.0 million shares to the plan, which was approved by our stockholders at the Annual Stockholders Meeting in June 2021. At September 30, 2021, the Company had approximately 10.8 million shares that remain available for issuance under the LTIP.

For 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 200% of the awards granted. The grant date fair value ranged from $1.06 to $9.52 per award. The Monte Carlo simulation model utilized multiple input variables that determined the probability of satisfying the market condition stipulated in the award grant and calculated the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 50.0% to 52.0%. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.2% to 2.5%. For the restricted stock units awarded in 2019 and 2020, the Monte Carlo simulation model included estimated quarterly dividend inputs ranging from $0.000 to $0.050.

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11. Income Taxes

We evaluate our estimated annual effective income tax rate each quarter, based on current and forecasted business results and enacted tax laws, 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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In thousands)
United States	$	(19,129)	$	(41,359)	$	(57,769)	$	(311,200)
Foreign	(8,847)		4,867		(141,400)		(89,332)
Income (loss) before income taxes	$	(27,976)	$	(36,492)	$	(199,169)	$	(400,532)

For the three months ended September 30, 2021 and 2020, our effective tax rate was 2% and 2%, respectively. For the nine months ended, September 30, 2021 and 2020, our effective tax rate was 11% and 5%, respectively. For the three and nine months ended September 30, 2021 and 2020, our overall effective tax rates were impacted by:

•The difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations,

•Jurisdictions that have a 0% statutory rate or where we have incurred losses and have recorded valuation allowances against the corresponding net deferred tax assets, and

•Other non-deductible expenses primarily in the U.S.

Additionally, for the nine months ended, September 30, 2020, our overall effective tax rate was impacted by:

•$30.9 million deferred tax expense related valuation allowances on U.S. deferred tax assets recognized in prior periods, and

•$4.9 million tax benefit associated with a 2018 U.S. tax loss carry back, pursuant to the Coronavirus Aid, Relief, and Economic Security ACT (“CARES ACT”), to an earlier tax year with a higher statutory tax rate.

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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,
	2021		2020		2021		2020
	(In thousands, except per share data)
Numerator:
Net loss allocable to common stockholders	$	(28,597)	$	(37,384)	$	(176,552)	$	(419,542)




Denominator:
Weighted average number of shares outstanding:
Basic	408,520		405,409		408,009		405,131
Restricted stock awards and units(1)	—		—		—		—
Diluted	408,520		405,409		408,009		405,131
Net loss per share:
Basic	$	(0.07)	$	(0.09)	$	(0.43)	$	(1.04)
Diluted	$	(0.07)	$	(0.09)	$	(0.43)	$	(1.04)

__________________________________

(1)We excluded outstanding restricted stock units of 15.4 million and 11.6 million for the three months ended September 30, 2021 and 2020, respectively, and 15.0 million and 11.4 million for the nine months ended September 30, 2021 and 2020, 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 one exploration well in Mauritania and a $200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue FPSO.

Performance Obligations

As of September 30, 2021 and December 31, 2020, the Company had performance bonds totaling $229.3 million and $195.5 million, respectively, for our supplemental bonding requirements stipulated by the BOEM and $3.5 million and $7.1 million, respectively, to third parties related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in our U.S. Gulf of Mexico fields. As of September 30, 2021 and December 31, 2020, we had zero cash collateral against these secured performance bonds.

Dividends

On March 26, 2020, the quarterly cash dividend of $0.0452 per common share was paid to stockholders of record as of March 5, 2020. In March 2020, in response to economic conditions, including oil price volatility and the impact of the COVID-19 pandemic, the Board of Directors decided to suspend the dividend.

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14. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:


	September 30, 2021		December 31, 2020
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	56,941	$	89,162
Revenue payable	20,737		15,079
Current asset retirement obligations	5,130		7,255
General and administrative expenses	19,773		4,988
Interest	34,222		23,725
Income taxes	15,443		37,344
Taxes other than income	3,765		2,815
Derivatives	19,850		17,475
Other	4,864		5,417
	$	180,725	$	203,260

Asset Retirement Obligations

The following table summarizes the changes in the Company's asset retirement obligations as of and during the nine months ended September 30, 2021:


	September 30, 2021
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	251,421
Liabilities incurred during period	6,419
Liabilities settled during period	(2,828)
Revisions in estimated retirement obligations	445
Accretion expense	15,082
Ending asset retirement obligations	$	270,539

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,
	2021		2020		2021		2020
	(In thousands)
(Gain) loss on disposal of inventory	$	(280)	$	1,200	$	302	$	3,028
(Gain) loss on asset retirement obligations liability settlements	58		(170)		444		1,952

Restructuring charges	(127)		(72)		710		13,268
Other, net	543		1,847		(453)		9,714
Other expenses, net	$	194	$	2,805	$	1,003	$	27,962

The restructuring charges are for employee severance and related benefit costs incurred as part of a corporate reorganization.

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15. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At September 30, 2021, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. To assess performance of the reporting segments, the Chief Operating Decision Maker reviews capital expenditures. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each area is presented below:


	Ghana		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Three months ended September 30, 2021
Revenues and other income:
Oil and gas revenue	$	67,247	$	35,063	$	—	$	96,626	$	—	$	—	$	198,936
Gain on sale of assets	—		—		—		—		1,538		—		1,538
Other income, net	—		—		—		256		65,941		(66,131)		66
Total revenues and other income	67,247		35,063		—		96,882		67,479		(66,131)		200,540
Costs and expenses:
Oil and gas production	10,490		13,029		—		26,797		—		—		50,316
Facilities insurance modifications, net	1,555		—		—		—		(1)		—		1,554
Exploration expenses	89		2,089		7,081		13,975		748		—		23,982
General and administrative	3,165		581		2,980		4,177		39,464		(27,908)		22,459
Depletion, depreciation and amortization	20,958		5,999		15		37,551		391		—		64,914
Impairment of long-lived assets	—		—		—		—		—		—		—
Interest and other financing costs, net(1)	16,836		(446)		(11,604)		3,446		18,641		—		26,873
Derivatives, net	—		—		—		—		38,224		—		38,224
Other expenses, net	34,382		3,229		(106)		648		265		(38,224)		194
Total costs and expenses	87,475		24,481		(1,634)		86,594		97,732		(66,132)		228,516
Loss before income taxes	(20,228)		10,582		1,634		10,288		(30,253)		1		(27,976)
Income tax expense (benefit)	(6,782)		5,758		—		—		1,645		—		621
Net loss	$	(13,446)	$	4,824	$	1,634	$	10,288	$	(31,898)	$	1	$	(28,597)

Consolidated capital expenditures	$	30,935	$	20,351	$	13,734	$	21,188	$	(162)	$	—	$	86,046

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	Ghana		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Nine months ended September 30, 2021
Revenues and other income:
Oil and gas revenue	$	313,126	$	147,424	$	—	$	298,905	$	—	$	—	$	759,455
Gain on sale of assets	—		—		—		—		1,564		—		1,564
Other income, net	1		—		—		1,028		347,866		(348,685)		210
Total revenues and other income	313,127		147,424		—		299,933		349,430		(348,685)		761,229
Costs and expenses:
Oil and gas production	80,189		56,373		—		75,309		—		—		211,871
Facilities insurance modifications, net	3,495		—		—		—		—		—		3,495
Exploration expenses	164		4,666		10,812		20,541		5,269		—		41,452
General and administrative	8,636		2,883		7,677		12,620		129,108		(94,296)		66,628
Depletion, depreciation and amortization	132,232		34,474		46		124,598		1,266		—		292,616
Impairment of long-lived assets	—		—		—		—		—		—		—
Interest and other financing costs, net(1)	36,890		(1,218)		(33,816)		12,307		78,348		(1,784)		90,727
Derivatives, net	—		—		—		—		252,606		—		252,606
Other expenses, net	193,370		34,096		(2,348)		26,185		2,306		(252,606)		1,003
Total costs and expenses	454,976		131,274		(17,629)		271,560		468,903		(348,686)		960,398
Loss before income taxes	(141,849)		16,150		17,629		28,373		(119,473)		1		(199,169)
Income tax expense (benefit)	(48,770)		19,957		—		—		6,196		—		(22,617)
Net loss	$	(93,079)	$	(3,807)	$	17,629	$	28,373	$	(125,669)	$	1	$	(176,552)

Consolidated capital expenditures	$	61,570	$	51,444	$	169,158	$	65,674	$	5,564	$	—	$	353,410

As of September 30, 2021
Property and equipment, net	$	1,226,513	$	447,795	$	822,013	$	925,384	$	21,192	$	—	$	3,442,897
Total assets	$	1,297,303	$	854,530	$	1,329,267	$	3,216,368	$	14,315,531	$	(16,859,275)	$	4,153,724

______________________________________

(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.

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	Ghana		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Three months ended September 30, 2020
Revenues and other income:
Oil and gas revenue	$	125,636	$	43,530	$	—	$	55,620	$	—	$	—	$	224,786
Gain on sale of assets	—		—		—		—		—		—		—
Other income, net	1		—		—		37		33,003		(33,040)		1
Total revenues and other income	125,637		43,530		—		55,657		33,003		(33,040)		224,787
Costs and expenses:
Oil and gas production	48,709		14,072		—		21,496		—		—		84,277
Facilities insurance modifications, net	2,465		—		—		—		—		—		2,465
Exploration expenses	48		1,561		806		5,485		6,077		—		13,977
General and administrative	3,101		1,017		1,168		3,580		39,472		(30,069)		18,269
Depletion, depreciation and amortization	63,487		15,421		15		31,499		809		—		111,231
Impairment of long-lived assets	—		—		—		—		—		—		—
Interest and other financing costs, net(1)	13,117		(344)		(6,607)		4,372		18,314		(1,784)		27,068
Derivatives, net	—		—		—		—		1,187		—		1,187
Other expenses, net	(1,818)		384		658		3,250		1,518		(1,187)		2,805
Total costs and expenses	129,109		32,111		(3,960)		69,682		67,377		(33,040)		261,279
Income (loss) before income taxes	(3,472)		11,419		3,960		(14,025)		(34,374)		—		(36,492)
Income tax expense (benefit)	(849)		7,048		—		—		(5,307)		—		892
Net income (loss)	$	(2,623)	$	4,371	$	3,960	$	(14,025)	$	(29,067)	$	—	$	(37,384)

Consolidated capital expenditures	$	6,116	$	9,853	$	46,574	$	30,677	$	6,287	$	—	$	99,507

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	Ghana		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Nine months ended September 30, 2020
Revenues and other income:
Oil and gas revenue	$	236,536	$	95,050	$	—	$	198,294	$	—	$	—	$	529,880
Gain on sale of assets	—		—		—		—		—		—		—
Other income, net	2		—		—		488		42,258		(42,746)		2
Total revenues and other income	236,538		95,050		—		198,782		42,258		(42,746)		529,882
Costs and expenses:
Oil and gas production	113,319		50,961		—		70,347		—		—		234,627
Facilities insurance modifications, net	10,555		—		—		—		—		—		10,555
Exploration expenses	146		6,397		5,265		26,046		36,439		—		74,293
General and administrative	10,123		3,977		5,453		10,433		99,551		(72,171)		57,366
Depletion, depreciation and amortization	148,135		43,724		46		132,213		2,272		—		326,390
Impairment of long-lived assets	—		—		—		150,820		—		—		150,820
Interest and other financing costs, net(1)	41,270		(1,044)		(19,455)		12,052		55,705		(5,351)		83,177
Derivatives, net	—		—		—		—		(34,776)		—		(34,776)
Other expenses, net	(64,142)		(8,993)		3,129		46,995		16,197		34,776		27,962
Total costs and expenses	259,406		95,022		(5,562)		448,906		175,388		(42,746)		930,414
Income (loss) before income taxes	(22,868)		28		5,562		(250,124)		(133,130)		—		(400,532)
Income tax expense (benefit)	(6,679)		(1,622)		—		30,902		(3,591)		—		19,010
Net income (loss)	$	(16,189)	$	1,650	$	5,562	$	(281,026)	$	(129,539)	$	—	$	(419,542)

Consolidated capital expenditures	$	31,192	$	25,959	$	51,897	$	109,228	$	32,082	$	—	$	250,358

As of September 30, 2020
Property and equipment, net	$	1,373,126	$	449,020	$	502,355	$	1,015,905	$	25,898	$	—	$	3,366,304
Total assets	$	1,511,667	$	708,614	$	717,323	$	3,221,915	$	12,782,894	$	(14,848,912)	$	4,093,501

______________________________________

(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.

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	Nine Months Ended September 30,
	2021		2020
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	377,125	$	215,425
Other property	725		1,838
Adjustments:
Changes in capital accruals	(16,523)		(6,284)
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	24,680		49,955
Capitalized interest	(31,956)		(18,062)
Proceeds on sale of assets	(3,395)		—
Other	2,754		7,486
Total consolidated capital expenditures	$	353,410	$	250,358

______________________________________

(1)Unsuccessful well costs are included in oil and gas assets when incurred.

16. Subsequent Events

In October 2021, Kosmos completed the acquisition of Anadarko WCTP Company (“Anadarko WCTP”), a subsidiary of Occidental Petroleum Corporation, which owns a participating interest in the WCTP Block and DT Block offshore Ghana, including an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN fields. In consideration for the acquisition, Kosmos paid approximately $460.0 million in cash based on an initial purchase price of $550.6 million reduced by certain purchase price adjustments totaling $94.7 million. Following closing of the Acquisition, Kosmos’ interest in the Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN fields increased from 17.0% to 28.1%.

Kosmos initially funded the purchase price through the issuance of $400.0 million aggregate principal amount of floating rate senior notes due 2022 (the “Bridge Notes”) and $75.0 million of borrowings under Kosmos' Facility. Kosmos then refinanced the Bridge Notes in full with the proceeds from the issuance of $400.0 million of 7.750% Senior Notes due 2027 and cash on hand. Kosmos also received $136.6 million in proceeds from a public issuance of 43.1 million shares of Kosmos’ common stock with plans to use the proceeds to repay outstanding borrowings under the Facility during the fourth quarter of 2021.

Under the Deepwater Tano Block Joint Operating Agreement, certain joint venture partners have pre-emption rights that, if fully exercised, could reduce our ultimate interest in the Jubilee Unit Area by 3.8% to 38.3%, and our ultimate interest in the TEN fields by 8.3% to 19.8%. This pre-emption right exists until November 12, 2021.

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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, 2020, 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 full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration program in Equatorial Guinea, Ghana and U.S. Gulf of Mexico.

The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in travel restrictions, including border closures, travel bans, social distancing restrictions and office closures being ordered in the various countries in which we operate, impacting some of our business operations. These ongoing restrictions have had an impact on the supply chain, resulting in the delay of various operational projects. Globally, the impact of COVID-19 has impacted demand for oil, which also resulted in significant variations in oil prices. The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on oil prices.

Recent Developments

Corporate

During the third quarter of 2021, Kosmos received the remaining proceeds of $1.0 million from Shell relating to Kosmos’ participating interest in South Africa as part of the agreement with Shell to farm down interests in a portfolio of frontier exploration assets.

Ghana

During the third quarter of 2021, Ghana production averaged approximately 108,200 Bopd gross (22,700 Bopd net). Jubilee production averaged approximately 77,800 Bopd gross (17,800 Bopd net) with consistent water injection and gas offtake and TEN production averaged approximately 30,400 Bopd gross (4,900 Bopd net). In the third quarter of 2021, the multi-year development drilling program continued to progress, with the successful completion of one producer and one water injector well in the Jubilee Field. The first Jubilee producer well (J-56P) started production in July 2021 and the Jubilee injector

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well (J-55W) came online in September 2021. In October 2021, the TEN gas injector well (NT-06G) was successfully completed and brought online. The rig then moved to drill and complete the second Jubilee producer well (J57-P), which is expected online around year-end.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 17,000 Boepd net (~81% oil) for the third quarter of 2021. The impact of the unplanned downtime from hurricanes to production in the U.S. Gulf of Mexico was approximately 4,000 barrels of oil equivalent per day in the third quarter or 1,000 barrels of oil equivalent to the full year compared to our previous production forecasts for 2021. Production has now returned to around pre-hurricane levels.

In April 2021, the Kodiak #3 infill well located in Mississippi Canyon Block 727 (29.1% working interest) was brought online with one of two zones intermittently producing. During the third quarter of 2021, the well continued to experience production issues and has been shut-in. We are currently working with our partners to evaluate the best options to enhance production from the Kodiak field.

During the second quarter of 2021, the Tornado-5 infill well located in the Green Canyon Block 281 (35.0% working interest) was successfully drilled and completed. The Tornado-5 well was brought online in July 2021 and is performing at the top end of expectations.

In January 2021, we announced the Winterfell exploration well encountered approximately 26 meters (85 feet) of net oil pay in two intervals. Winterfell was designed to test a sub-salt Upper Miocene prospect located in Green Canyon Block 944. In September 2021, we spudded an appraisal well to the Winterfell discovery in Green Canyon Block 943, with results expected in the fourth quarter of 2021. The appraisal well is planned to evaluate the adjacent fault block to the northwest of the original discovery, which has the same seismic signature as the Winterfell exploration well, with an exploration tail into a deeper horizon. The results of the appraisal well will also help refine development options for the discovery.

In July 2021, the Company commenced drilling the Zora infrastructure-led exploration prospect located in DeSoto Canyon Block 266 (37.5% working interest). The well did not find hydrocarbons and was plugged and abandoned in August 2021. The well results will be integrated into the ongoing evaluation of the surrounding area. The Company recorded approximately $14.1 million of exploration expense for the nine months ended September 30, 2021 related to the well.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 29,900 Bopd gross (9,600 Bopd net) in the third quarter of 2021. In April 2021, one ESP conversion was completed with two additional ESP conversions planned to be completed in 2022. The first of three planned infill wells in the Okume Complex was completed in August 2021 with hookup currently in progress. In the third quarter of 2021, the operator commenced drilling the an additional well, which is expected to be online in the fourth quarter of 2021. The third planned well is now expected to be deferred, as the rig is being utilized to plug and abandon an existing well in Equatorial Guinea and is required to mobilize for its’ next contract before it can complete the drilling of the last well.

Mauritania and Senegal

During the first quarter of 2021, BP, as the operator of the Cayar block offshore Senegal, provided notice to the Government of Senegal requesting an extension of the current license phase in order to provide the block owners additional time to evaluate the natural gas market for the natural gas discovery at Yakaar Teranga. On July 5, 2021 a presidential decree was issued extending the term of the license for up to an additional three years.

Greater Tortue Ahmeyim Unit

Phase 1 of the Greater Tortue project continues to make steady progress in 2021 with first gas for the project expected in the third quarter of 2023. The following milestones were achieved as of the end of the third quarter of 2021 and post quarter-end:

•FLNG: Mechanical completion activities have commenced with instrument loop checks

•FPSO: Topsides integration and hull and living quarters mechanical completion activities have commenced

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•Breakwater: Commenced fabrication of 20th caisson (of 21) with 12 installed

•Subsea: Nouakchott and Dakar marine supply bases established

As a result of the above transactions entered into by BP Operator, Kosmos has recognized a Long-term receivable of $200.2 million from BP Operator for our share of the consideration paid from BP Buyer to and held by BP Operator as well as a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Tortue FPSO. This Long-term receivable will be non-cash settled against obligations payable to BP Operator. During the third quarter of 2021, BP Operator settled our payment obligations of $51.2 million of capital expenditures and $42.7 million of existing Accounts Payable to BP Operator.

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Results of Operations

All of our results, as presented in the table below, represent operations from Jubilee and TEN fields in Ghana, the U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the three and nine months ended September 30, 2021 and 2020 are included in the following tables:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	2,719		5,160		11,349		14,361
Gas (MMcf)	1,078		1,167		3,624		4,451
NGL (MBbl)	111		122		365		457
Total (MBoe)	3,010		5,477		12,318		15,560
Total (Boepd)	32,714		59,527		45,121		56,788

Revenues:
Oil sales	$	190,599	$	220,653	$	737,381	$	517,382
Gas sales	4,508		2,314		12,727		8,146
NGL sales	3,829		1,819		9,347		4,352
Total revenues	$	198,936	$	224,786	$	759,455	$	529,880

Average oil sales price per Bbl	$	70.10	$	42.76	$	64.97	$	36.03
Average gas sales price per Mcf	4.18		1.98		3.51		1.83
Average NGL sales price per Bbl	34.50		14.91		25.61		9.52
Average total sales price per Boe	66.10		41.05		61.65		34.05

Costs:
Oil and gas production, excluding workovers	$	47,182	$	87,998	$	201,975	$	233,141
Oil and gas production, workovers	3,134		(3,721)		9,896		1,486
Total oil and gas production costs	$	50,316	$	84,277	$	211,871	$	234,627

Depletion, depreciation and amortization	$	64,914	$	111,231	$	292,616	$	326,390

Average cost per Boe:
Oil and gas production, excluding workovers	$	15.68	$	16.07	$	16.40	$	14.98
Oil and gas production, workovers	1.04		(0.68)		0.80		0.10
Total oil and gas production costs	16.72		15.39		17.20		15.08

Depletion, depreciation and amortization	21.57		20.31		23.76		20.98
Total	$	38.29	$	35.70	$	40.96	$	36.06

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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, 2021:


	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	—	—	—	—	—	—	9	2.17
TEN	—	—	1	0.17	—	—	5	0.85
Equatorial Guinea
Block S	—	—	—	—	1	0.40	—	—
Okume	—	—	1	0.43	—	—	1	0.43
U.S. Gulf of Mexico
Winterfell	1	0.16	—	—	1	0.18	—	—

Mauritania / Senegal
Mauritania C8	—	—	—	—	2	0.56	—	—
Greater Tortue Ahmeyim Unit	—	—	—	—	3	0.80	1	0.27
Senegal Cayar Profond	—	—	—	—	3	0.90	—	—
Total	1	0.16	2	0.60	10	2.84	16	3.72

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The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.

Three months ended September 30, 2021 compared to three months ended September 30, 2020


	Three Months Ended
	September 30,				Increase
	2021		2020		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	198,936	$	224,786	$	(25,850)
Gain on sale of assets	1,538		—		1,538
Other income, net	66		1		65
Total revenues and other income	200,540		224,787		(24,247)
Costs and expenses:
Oil and gas production	50,316		84,277		(33,961)
Facilities insurance modifications, net	1,554		2,465		(911)
Exploration expenses	23,982		13,977		10,005
General and administrative	22,459		18,269		4,190
Depletion, depreciation and amortization	64,914		111,231		(46,317)

Interest and other financing costs, net	26,873		27,068		(195)
Derivatives, net	38,224		1,187		37,037
Other expenses, net	194		2,805		(2,611)
Total costs and expenses	228,516		261,279		(32,763)
Loss before income taxes	(27,976)		(36,492)		8,516
Income tax expense	621		892		(271)
Net loss	$	(28,597)	$	(37,384)	$	8,787

Oil and gas revenue. Oil and gas revenue decreased by $25.9 million as a result of lower sales volumes due to cargo timing in our international operations partially offset by higher oil prices. We sold 3,010 MBoe at an average realized price per barrel equivalent of $66.10 during the three months ended September 30, 2021 and 5,477 MBoe at an average realized price per barrel equivalent of $41.05 during the three months ended September 30, 2020.

Oil and gas production. Oil and gas production costs decreased by $34.0 million during the three months ended September 30, 2021, as compared to the three months ended September 30, 2020 primarily as a result of lower sales volumes in the current quarter offset by increased workover costs and higher production costs per barrel from the field production mix in the U.S. Gulf of Mexico.

General and administrative. General and administrative costs increased by $4.2 million during the three months ended September 30, 2021, as compared with the three months ended September 30, 2020 primarily as a result of not accruing employee bonuses in 2020 as part of management’s response to COVID-19.

Exploration expenses. Exploration expenses increased by $10.0 million during the three months ended September 30, 2021, as compared to the three months ended September 30, 2020 primarily as result of the Zora exploration well. The well did not find hydrocarbons and was plugged and abandoned in August 2021 with $12.6 million of well costs charged to exploration expense for the three months ended September 30, 2021.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $46.3 million during the three months ended September 30, 2021, as compared with the three months ended September 30, 2020 primarily as a result of lower sales volumes during the current quarter.

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Derivatives, net. During the three months ended September 30, 2021 and 2020, we recorded a loss of $38.2 million and a loss of $1.2 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.

Income tax expense (benefit). For the three months ended September 30, 2021 and 2020, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

Nine months ended September 30, 2021 compared to nine months ended September 30, 2020



	Nine Months Ended
	September 30,				Increase
	2021		2020		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	759,455	$	529,880	$	229,575
Gain on sale of assets	1,564		—		1,564
Other income, net	210		2		208
Total revenues and other income	761,229		529,882		231,347
Costs and expenses:
Oil and gas production	211,871		234,627		(22,756)
Facilities insurance modifications, net	3,495		10,555		(7,060)
Exploration expenses	41,452		74,293		(32,841)
General and administrative	66,628		57,366		9,262
Depletion, depreciation and amortization	292,616		326,390		(33,774)
Impairment of long-lived assets	—		150,820		(150,820)
Interest and other financing costs, net	90,727		83,177		7,550
Derivatives, net	252,606		(34,776)		287,382
Other expenses, net	1,003		27,962		(26,959)
Total costs and expenses	960,398		930,414		29,984
Loss before income taxes	(199,169)		(400,532)		201,363
Income tax expense	(22,617)		19,010		(41,627)
Net loss	$	(176,552)	$	(419,542)	$	242,990

Oil and gas revenue. Oil and gas revenue increased by $229.6 million as a result of higher oil prices partially offset by lower sales volumes due to lower production rates resulting in fewer scheduled liftings from our international operations. We sold 12,318 MBoe at an average realized price per barrel equivalent of $61.65 during the nine months ended September 30, 2021 and 15,560 MBoe at an average realized price per barrel equivalent of $34.05 during the nine months ended September 30, 2020.

Oil and gas production. Oil and gas production costs decreased by $22.8 million during the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020 primarily as a result of lower sales and production volumes in the current year (including TEN fields offshore Ghana) offset by higher production costs per barrel from the field production mix in the U.S. Gulf of Mexico.

Facilities insurance modifications, net. During the nine months ended September 30, 2021 and 2020, we recorded $3.5 million and $10.6 million, respectively related to facilities insurance modifications associated with the long-term solution to the Jubilee turret bearing.

Exploration expenses. Exploration expenses decreased by $32.8 million during the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020. The decrease is primarily a result of lower geological, geophysical, and seismic costs incurred in 2021 versus the prior period related to the U.S. Gulf of Mexico business unit and

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other exploration license areas sold to Shell in 2020. This decrease is partially offset by the Zora exploration well which did not find hydrocarbons and was plugged and abandoned in August 2021 with $14.1 million of well costs charged to exploration expense for the nine months ended September 30, 2021.

General and administrative. General and administrative costs increased by $9.3 million during the nine months ended September 30, 2021, as compared with the nine months ended September 30, 2020 primarily as a result of not accruing employee bonuses in 2020 as part of management’s response to COVID-19 offset by reduced expenditures on general office costs.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $33.8 million during the nine months ended September 30, 2021, as compared with the nine months ended September 30, 2020 primarily as a result of lower sales volumes in the current year partially offset by higher depletion rates from a reduction of proved reserves in the fourth quarter of 2020 and field production mix.

Impairment of long-lived assets. As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, we recorded asset impairments totaling $150.8 million during the nine months ended September 30, 2020 for oil and gas proved properties in the U.S. Gulf of Mexico. We did not recognize impairment of proved oil and gas properties during the nine months ended September 30, 2021 as no impairment indicators were identified.

Interest and other financing costs, net. Interest and other financing costs, net increased $7.6 million primarily a result of $15.2 million for loss on extinguishment of debt during the second quarter of 2021 related to the Facility amendment offset by increased interest income on long-term receivable balances from GNPC in Ghana and the national oil companies in Mauritania and Senegal during the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020.

Derivatives, net. During the nine months ended September 30, 2021 and 2020, we recorded a loss of $252.6 million and a gain of $34.8 million, respectively, on our outstanding hedge positions. The changes recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net decreased $27.0 million during the nine months ended September 30, 2021, as compared with the nine months ended September 30, 2020 primarily related to $13.3 million in restructuring charges for employee severance and related benefit costs and $5.7 million of asset impairments recorded in 2020. In addition, we received $8.1 million of insurance recoveries in 2021.

Income tax expense (benefit). For the nine months ended September 30, 2021 and 2020, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S. Additionally for September 30, 2020, our overall effective tax rate was impacted by a $30.9 million deferred tax expense related to valuation allowances on U.S. deferred tax assets recognized in a prior periods, and a $4.9 million tax benefit associated with the Coronavirus Aid, Relief and Economic Security ACT (“CARES ACT”).

Liquidity and Capital Resources

We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to our strategy as a full-cycle exploration and production company. 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.

Current oil prices are volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could result in wide fluctuations in future oil prices, which could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program, partner carries and our current liquidity position support our remaining capital program for 2021.

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Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the nine months ended September 30, 2021 and 2020:


	Nine Months Ended
	September 30,
	2021		2020
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	143,841	$	20,657
Net proceeds from issuance of senior notes	444,375		—
Borrowings under long-term debt	250,000		300,000
Advances under production prepayment agreement	—		50,000
Proceeds on sale of assets	5,327		1,713
	843,543		372,370
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	377,125		215,425
Other property	725		1,838

Notes receivable from partners	41,712		53,574
Payments on long-term debt	400,000		—
Purchase of treasury stock	1,100		4,947
Dividends	512		19,174
Deferred financing costs	17,291		4,570
	838,465		299,528
Increase in cash, cash equivalents and restricted cash	$	5,078	$	72,842

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2021 was $143.8 million compared with net cash provided by operating activities for the nine months ended September 30, 2020 of $20.7 million. The increase in cash provided by operating activities in the nine months ended September 30, 2021 when compared to the same period in 2020 is primarily a result of increased oil prices.

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The following table presents our net debt and liquidity as of September 30, 2021:


	September 30, 2021
	(In thousands)
Cash and cash equivalents	$	111,329
Restricted cash	43,513
7.125% Senior Notes	650,000
7.500% Senior Notes	450,000
Borrowings under the Facility	1,150,000
Borrowings under the Corporate Revolver	—
Borrowings under the GoM Term Loan	200,000
Net debt	$	2,295,158

Availability under the Facility	$	85,155
Availability under the Corporate Revolver	$	400,000
Available borrowings plus cash and cash equivalents	$	596,484

Capital Expenditures and Investments

We expect to incur capital costs as we:

• drill additional wells and execute exploitation activities in Ghana, Equatorial Guinea and in the U.S. Gulf of Mexico;

• execute infrastructure-led exploration and appraisal efforts in the U.S. Gulf of Mexico and Equatorial Guinea; and

• execute exploration, appraisal and development activities in Mauritania and Senegal.

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, paying 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, 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, health, 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 assets, 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.

2021 Capital Program

We estimate we will spend around $300 million of capital, which includes the additional acquired interests in Ghana and excludes amounts related to Mauritania and Senegal, in our base business for the year ending December 31, 2021. Through September 30, 2021, we have spent approximately $184.3 million on base business capital expenditures.

Capital expenditures associated with the Greater Tortue project in 2021 net to Kosmos was previously estimated to be around $350 million. With the completion of the Greater Tortue FPSO sale transaction in August 2021, our 2021 capital expenditures associated with the Greater Tortue project have been reduced to around $180 million, with the remaining cash calls on the Greater Tortue project for 2021 covered through the proceeds of the sale. The balance of the sale proceeds, as well as the additional savings from the transfer of the remaining FPSO construction payments to BP Buyer, are expected to be largely realized in 2022. Through September 30, 2021, we have spent approximately $169.2 million of capital expenditures related to Mauritania and Senegal.

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In relation to the additional capital expenditures associated with the additional acquired interests in Ghana, certain joint venture partners have pre-emption rights under the Deepwater Tano Block Joint Operating Agreement that, if fully exercised, could reduce our ultimate interest in the Jubilee Unit Area by 3.8% to 38.3%, and our ultimate interest in the TEN fields by 8.3% to 19.8%. This pre-emption right exists until November 12, 2021 and, if exercised, will reduce our capital expenditures associated with the additional acquired interests.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our exploitation and drilling results among other factors. 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 multi-faceted infrastructure-led exploration and appraisal drilling programs, 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 exploitation, 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

•the extension of the maturity date by two years (final maturity date now occurs on March 31, 2027),

•the extension of the amortization schedule such that amortization of principal is to commence on March 31, 2024 and continue in equal amounts every six months thereafter until the maturity date,

•an increase in the interest margin by 0.5% (applicable interest margin for the first three years is now LIBOR +3.75%),

•an increase in the Loan Life Coverage Ratio from 1.10x to 1.30x after March 31, 2024,

•the removal of Kosmos Energy Investments Senegal Limited, Kosmos Energy Senegal and Kosmos Energy Mauritania as borrowers, guarantors and pledged subsidiaries, and

•a reduction in the Facility size to $1.25 billion (from $1.5 billion).

As amended, the Facility has an available borrowing base of approximately $1.24 billion. As part of the amendment, the Company incurred $15.2 million for loss on extinguishment of debt during the second quarter of 2021. During the September 2021 redetermination, the Company’s lending syndicate approved a borrowing base capacity in excess of the facility size of $1.25 billion.

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Corporate Revolver

As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, in July 2020, we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation through December 31, 2021. The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. We were in compliance with the financial covenants as of the most recent assessment date. The Corporate Revolver contains customary cross default provisions.

7.125% Senior Notes due 2026

7.500% Senior Notes due 2028

The 7.500% Senior Notes mature on March 1, 2028. Interest is payable in arrears each March 1 and September 1, commencing on September 1, 2021. The 7.500% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver and the 7.125% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.500% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and, on a subordinated basis, guarantee the Corporate Revolver and the 7.125% Senior Notes.

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Production Prepayment Agreement

GoM Term Loan

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2021 and the weighted average interest rates expected to be paid on the Facility, Corporate Revolver and GoM Term Loan given current contractual terms and market conditions, and the instrument’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 include amortization of deferred financing costs.


																					Asset
																					(Liability)
																					Fair Value at
	Years Ending December 31,																				September 30,
	2021(2)			2022			2023			2024			2025			Thereafter			Total		2021
	(In thousands, except percentages)
Fixed rate debt:
7.125% Senior Notes	$	—		$	—		$	—		$	—		$	—		$	650,000		$	650,000	$	(637,728)
7.500% Senior Notes	—			—			—			—			—			450,000			450,000		(436,905)

Variable rate debt:
Weighted average interest rate on variable rate debt	4.22		%	4.26		%	4.63		%	5.36		%	5.77		%	6.38		%
Facility(1)	$	—		$	—		$	112,621		$	207,834		$	300,192		$	529,353		$	1,150,000	$	(1,150,000)

GoM Term Loan	7,500			30,000			30,000			30,000			102,500			—			200,000		(200,000)

Total principal debt repayments(1)	$	7,500		$	30,000		$	142,621		$	237,834		$	402,692		$	1,629,353		$	2,450,000
Interest & commitment fee payments on long-term debt	39,498			140,981			140,117			138,484			124,287			133,143			716,510
Operating leases	426			3,932			4,075			4,146			4,217			15,161			31,957

__________________________________

(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of September 30, 2021. 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.

(2)Represents the period October 1, 2021 through December 31, 2021.

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The table above 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. The Company's liabilities for asset retirement obligations associated with the dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 14 — Additional Financial Information for additional information regarding these liabilities.

We currently have a commitment to drill one exploration well in Mauritania and a $200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue FPSO.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of September 30, 2021, our off-balance sheet arrangements and transactions include short-term 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, leases 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. Other than items discussed in Note 2 — Accounting Policies, 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, 2020.

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:

•the impact of the COVID-19 pandemic on the Company and the overall business environment;

•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 to us by the governments of the countries in which we operate (or their respective national oil companies) or any other federal, state or local governments or authorities;

•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, natural gas and NGL prices, as well as our ability to implement hedges addressing such volatility on commercially reasonable terms;

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

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

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•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, or new, environmental, health and safety or climate change or GHG laws, regulations and executive orders, or the implementation, or interpretation, of those laws, regulations and executive orders;

•adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;

•environmental liabilities;

•geological, geophysical and other technical and operations problems, 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, including tropical storms and hurricanes in the Gulf of Mexico;

•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, performance bonds 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 our quarterly reports 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 9 — Derivative Financial Instruments and Note 10— Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.

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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, 2021:


	Derivative Contracts Assets (Liabilities)
	Commodities
	(In thousands)
Fair value of contracts outstanding as of December 31, 2020	$	(20,377)
Changes in contract fair value	(259,289)
Contract maturities	150,255
Fair value of contracts outstanding as of September 30, 2021	$	(129,411)

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. Substantially all of our oil sales are indexed against Dated Brent, and Heavy Louisiana Sweet. Oil prices in the first nine months of 2021 ranged between $50.34 and $79.12 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first nine months of 2021.

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 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. In addition, a reduction in our ability to access credit could reduce our ability to implement derivative contracts on commercially reasonable terms.

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, 2021. Volumes and weighted average prices are net of any offsetting derivatives entered into.


				Weighted Average Price per Bbl										Asset
				Net Deferred										(Liability)
				Premium										Fair Value at
				Payable/				Sold						September 30,
Term	Type of Contract	Index	MBbl	(Receivable)		Swap		Put		Floor		Ceiling		2021(2)
														(In thousands)
2021:
Oct — Dec	Swaps with sold puts	Dated Brent	1,500	$	—	$	53.96	$	42.92	$	—	$	—	$	(31,518)
Oct — Dec	Three-way collars	Dated Brent	750	0.45		—		32.50		40.00		53.47		(16,513)
Oct — Dec	Three-way collars	NYMEX WTI	250	1.00		—		37.50		45.00		55.00		(5,114)
Oct — Dec	Sold calls(1)	Dated Brent	1,750	—		—		—		—		70.09		(11,653)
2022:
Jan — Dec	Three-way collars	Dated Brent	4,500	0.64		—		43.33		56.67		76.91		(23,895)
Jan — Dec	Two-way collars	Dated Brent	3,000	1.26		—		—		55.00		76.67		(15,340)
Jan — Dec	Sold calls(1)	Dated Brent	1,581	—		—		—		—		60.00		(25,378)

__________________________________

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

(2)Fair values are based on the average forward oil prices on September 30, 2021.

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At September 30, 2021, our open commodity derivative instruments were in a net liability position of $129.4 million. As of September 30, 2021, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $79.0 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $68.1 million.

Interest Rate Sensitivity

Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Facility and GoM Term Loan, which as of September 30, 2021 total $1.4 billion and have a weighted average interest rate of 4.3%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. If the floating market rate increased 10% at this level of floating rate debt, we would pay an estimated additional $0.2 million interest expense per year. The commitment fees on the undrawn availability under the Facility and the Corporate Revolver are not subject to changes in interest rates. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. Additionally, a change in the market interest rates could impact interest costs associated with future debt issuances or any future borrowings.

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, 2021, 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.

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, 2020.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

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Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information.

There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K.

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 8, 2021	/s/ NEAL D. SHAH
		Neal D. Shah
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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INDEX OF EXHIBITS


Exhibit Number						Description of Document
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

___________________________________

Document

Exhibit 31.1

Certification of Chief Executive Officer

I, Andrew G. Inglis, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Kosmos Energy Ltd.;

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

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

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

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

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

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

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

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

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

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: November 8, 2021			/s/ ANDREW G. INGLIS
			Andrew G. Inglis
			Chairman of the Board of Directors and Chief Executive Officer
			(Principal Executive Officer)

Document

Exhibit 31.2

Certification of Chief Financial Officer

I, Neal D. Shah, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Kosmos Energy Ltd.;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: November 8, 2021			/s/ NEAL D. SHAH
			Neal D. Shah
			Senior Vice President and Chief Financial Officer
			(Principal Financial Officer)

Document

Exhibit 32.1

Certification of Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the accompanying quarterly report of Kosmos Energy Ltd. (the “Company”) on Form 10-Q for the quarter ended September 30, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Andrew G. Inglis, Chairman of the Board of Directors and Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Date: November 8, 2021			/s/ ANDREW G. INGLIS
			Andrew G. Inglis
			Chairman of the Board of Directors and Chief Executive Officer
			(Principal Executive Officer)

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Document

Exhibit 32.2

Certification of Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the accompanying quarterly report of Kosmos Energy Ltd. (the “Company”) on Form 10-Q for the quarter ended September 30, 2021, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Neal D. Shah, Senior Vice President and Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Date: November 8, 2021			/s/ NEAL D. SHAH
			Neal D. Shah
			Senior Vice President and Chief Financial Officer
			(Principal Financial Officer)