Kosmos Energy - 10-Q quarterly report FY2020 Q2

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2020



☐	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 July 30, 2020
Common Shares, $0.01 par value		405,410,075

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TABLE OF CONTENTS

Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its 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	2

Item 1. Financial Statements	6
Consolidated Balance Sheets	6
Consolidated Statements of Operations	7
Consolidated Statements of Stockholders’ Equity	8
Consolidated Statements of Cash Flows	9
Notes to Consolidated Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3. Quantitative and Qualitative Disclosures about Market Risk	46
Item 4. Controls and Procedures	48

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	48
Item 1A. Risk Factors	48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3. Defaults Upon Senior Securities	48
Item 4. Mine Safety Disclosures	48
Item 5. Other Information	49
Item 6. Exhibits	49
Signatures	50
Index to Exhibits	51

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.
“ASC”		Financial Accounting Standards Board Accounting Standards Codification.
“ASU”		Financial Accounting Standards Board Accounting Standards Update.

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“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.
“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.
"DGE"		Deep Gulf Energy (together with its subsidiaries).
"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.
“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. The Facility EBITDAX definition includes 50% of the EBITDAX adjustments of Kosmos-Trident International Petroleum Inc for the period it was an equity method investment and includes Last Twelve Months ("LTM") EBITDAX for any acquisitions and excludes LTM EBITDAX for any divestitures.
"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.
"FLNG"		Floating liquefied natural gas.
“FPS”		Floating production system.
“FPSO”		Floating production, storage and offloading vessel.
"Galp"		Galp Energia Sao Tome E Principe, Unipessoal, LDA.
"GEPetrol"		Guinea Equatorial De Petroleos.
"GHG"		Greenhouse gas.

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"GJFFDP"		Greater Jubilee Full Field Development Plan.
"GNPC"		Ghana National Petroleum Corporation.
GoM Liquidity Ratio		The "GoM Liquidity Ratio" is broadly defined, for each applicable forecast period, as the ratio of (1) net cash flow of our U.S. Gulf of Mexico business unit over the immediately succeeding six (6) months from the sale of the volumes of crude oil using certain agreed pricing metrics and models set forth in the Production Prepayment Agreement, to (2) the portion of the Prepaid Value to be delivered to Trafigura as determined by the Volume Model for the same six (6) month period.
“Greater Tortue Ahmeyim”		Ahmeyim and Guembeul discoveries.
"GTA UUOA"		Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
"Guarantor Liquidity Ratio"		The "Guarantor Liquidity Ratio" is broadly defined, for each applicable forecast period, as the ratio of (1) the sum of (A) projected revenues of the Company from the sale of hydrocarbons over the four quarters beginning on or after the calculation date, (B) the expected income from hedges then in effect (but not less than zero), (C) its cash balance as of the calculation date, and (D) the amount of the Prepayments available under the Production Prepayment Agreement and any other committed sources of capital of the Company, to (2) the sum of all forecast cash costs of the Company over the four quarters beginning on or after the calculation date.
"Hess"		Hess Corporation.
"HLS"		Heavy Louisiana Sweet.
"H&M"		Hull and Machinery insurance.
"Jubilee UUOA"		Unitization and Unit Operating Agreement covering the Jubilee Unit.
"KTEGI"		Kosmos-Trident Equatorial Guinea Inc.
"KTIPI"		Kosmos-Trident International Petroleum Inc.
"LNG"		Liquefied natural gas.
"LOPI"		Loss of Production Income.
"LSE"		London Stock Exchange.
"LTIP"		Long Term Incentive Plan.
“MBbl”		Thousand barrels of oil.
“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.
"NAMCOR"		National Petroleum Corporation of Namibia.
“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.
"PETROCI"		PETROCI Holding.
“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.

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"Prepaid Value"		As defined in the Production Prepayment Agreement attached as exhibit 10.3 hereto.
“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.
"Senior Notes"		7.125% Senior Notes due 2026.
"Senior Secured Notes"		7.875% Senior Secured Notes due 2021.
“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.
"SNPC"		Société Nationale des Pétroles du Congo.
“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.
“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.
"Volume Model"		As defined in the Production Prepayment Agreement attached as exhibit 10.3 hereto.
"WCTP"		West Cape Three Points.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	June 30, 2020			December 31, 2019
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	164,091		$	224,502
Restricted cash	186			4,302
Receivables:
Joint interest billings, net	56,267			81,424
Oil sales	33,497			64,142
Other	26,797			28,727
Inventories	130,299			114,412
Prepaid expenses and other	39,573			36,192
Derivatives	30,289			12,856
Total current assets	480,999			566,557
Property and equipment:
Oil and gas properties, net	3,365,746			3,624,751
Other property, net	12,919			17,581
Property and equipment, net	3,378,665			3,642,332
Other assets:
Restricted cash	542			542
Long-term receivables	88,137			43,430
Deferred financing costs, net of accumulated amortization of $15,989 and $14,681 at June 30, 2020 and December 31, 2019, respectively	5,013			6,321
Deferred tax assets	—			32,779
Derivatives	11,271			2,302
Other	21,864			22,969
Total assets	$	3,986,491		$	4,317,232
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	145,670		$	149,483
Accrued liabilities	203,275			380,704
Current maturities of long-term debt	56,000			—
Derivatives	43,974			8,914
Total current liabilities	448,919			539,101
Long-term liabilities:
Long-term debt, net	2,107,653			2,008,063
Production prepayment agreement, net	49,333			—
Derivatives	9,306			11,478
Asset retirement obligations	239,845			230,526
Deferred tax liabilities	644,091			653,221
Other long-term liabilities	33,157			33,141
Total long-term liabilities	3,083,385			2,936,429
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2020 and December 31, 2019	—			—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 449,574,638 and 445,779,367 issued at June 30, 2020 and December 31, 2019, respectively	4,496			4,458
Additional paid-in capital	2,291,826			2,297,221
Accumulated deficit	(1,605,128		)	(1,222,970		)
Treasury stock, at cost, 44,263,269 shares at June 30, 2020 and December 31, 2019, respectively	(237,007		)	(237,007		)
Total stockholders’ equity	454,187			841,702
Total liabilities and stockholders’ equity	$	3,986,491		$	4,317,232

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
Revenues and other income:
Oil and gas revenue	$	127,314		$	395,933		$	305,094		$	692,723
Other income, net	—			1			1			1
Total revenues and other income	127,314			395,934			305,095			692,724
Costs and expenses:
Oil and gas production	88,747			90,977			150,350			170,776
Facilities insurance modifications, net	52			2,278			8,090			(17,743		)
Exploration expenses	15,711			29,905			60,316			60,249
General and administrative	18,186			28,072			39,097			63,980
Depletion, depreciation and amortization	121,857			151,438			215,159			269,533
Impairment of long-lived assets	—			—			150,820			—
Interest and other financing costs, net	28,274			59,803			56,109			94,844
Derivatives, net	100,075			(14,185		)	(35,963		)	62,900
Other expenses, net	1,228			(1,793		)	25,157			326
Total costs and expenses	374,130			346,495			669,135			704,865
Income (loss) before income taxes	(246,816		)	49,439			(364,040		)	(12,141		)
Income tax expense (benefit)	(47,425		)	32,602			18,118			23,928
Net income (loss)	$	(199,391	)	$	16,837		$	(382,158	)	$	(36,069	)

Net income (loss) per share:
Basic	$	(0.49	)	$	0.04		$	(0.94	)	$	(0.09	)
Diluted	$	(0.49	)	$	0.04		$	(0.94	)	$	(0.09	)

Weighted average number of shares used to compute net income (loss) per share:
Basic	405,195			401,323			404,990			401,244
Diluted	405,195			408,230			404,990			401,244

Dividends declared per common share	$	—		$	0.0452		$	0.0452		$	0.0904

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
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 awards and units	3,590	36		(36		)	—			—			—
Purchase of treasury stock / tax withholdings	—	—		(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

2019:
Balance as of December 31, 2018	442,915	$	4,429	$	2,341,249		$	(1,167,193	)	$	(237,007	)	$	941,478
Dividends ($0.0452 per share)	—	—		(18,744		)	—			—			(18,744		)
Equity-based compensation	—	—		8,744			—			—			8,744
Restricted stock awards and units	2,610	26		(26		)	—			—			—
Purchase of treasury stock / tax withholdings	—	—		(1,979		)	—			—			(1,979		)
Net loss	—	—		—			(52,906		)	—			(52,906		)
Balance as of March 31, 2019	445,525	$	4,455	$	2,329,244		$	(1,220,099	)	$	(237,007	)	$	876,593
Dividends ($0.0452 per share)	—	—		(18,740		)	—			—			(18,740		)
Equity-based compensation	—	—		9,525			—			—			9,525
Restricted stock awards and units	113	1		(1		)	—			—			—
Purchase of treasury stock / tax withholdings	—	—		(4		)	—			—			(4		)
Net income	—	—		—			16,837			—			16,837
Balance as of June 30, 2019	445,638	$	4,456	$	2,320,024		$	(1,203,262	)	$	(237,007	)	$	884,211

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Six Months Ended June 30,
	2020			2019
Operating activities
Net loss	$	(382,158	)	$	(36,069	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	219,634			274,222
Deferred income taxes	23,650			(56,730		)
Unsuccessful well costs and leasehold impairments	20,855			7,099
Impairment of long-lived assets	150,820			—
Change in fair value of derivatives	(31,615		)	65,686
Cash settlements on derivatives, net (including $42.4 million and $(18.7) million on commodity hedges during 2020 and 2019)	34,814			(21,044		)
Equity-based compensation	17,693			17,932
Loss on extinguishment of debt	2,215			24,794
Other	6,529			7,417
Changes in assets and liabilities:
(Increase) decrease in receivables	57,593			(23,996		)
Increase in inventories	(17,715		)	(19,021		)
(Increase) decrease in prepaid expenses and other	(3,464		)	29,380
Decrease in accounts payable	(3,813		)	(76,031		)
Increase (decrease) in accrued liabilities	(157,874		)	28,751
Net cash provided by (used in) operating activities	(62,836		)	222,390
Investing activities
Oil and gas assets	(135,242		)	(153,268		)
Other property	(1,536		)	(5,230		)
Proceeds on sale of assets	1,713			—
Notes receivable from partners	(42,362		)	(5,983		)
Net cash used in investing activities	(177,427		)	(164,481		)
Financing activities
Borrowings under long-term debt	150,000			175,000
Payments on long-term debt	—			(300,000		)
Advances under production prepayment agreement	50,000			—
Net proceeds from issuance of senior notes	—			641,875
Redemption of senior secured notes	—			(535,338		)
Purchase of treasury stock / tax withholdings	(4,947		)	(1,983		)
Dividends	(19,181		)	(36,289		)
Deferred financing costs	(136		)	(1,981		)
Net cash provided by (used in) financing activities	175,736			(58,716		)
Net decrease in cash, cash equivalents and restricted cash	(64,527		)	(807		)
Cash, cash equivalents and restricted cash at beginning of period	229,346			185,616
Cash, cash equivalents and restricted cash at end of period	$	164,819		$	184,809

Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest	$	58,096		$	65,307
Income taxes	$	54,199		$	14,619

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Kosmos Energy Ltd. changed its jurisdiction of incorporation from Bermuda to the State of Delaware, in the United States of America, (the "Redomestication") in December 2018. 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 exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Namibia, Sao Tome and Principe, and South Africa). 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. In addition, we have exploration activities in other countries in the Atlantic Margins.

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 consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2019, included in our annual report on Form 10-K and our quarterly report on Form 10-Q for the quarter ended March 31, 2020.

Reclassifications

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

Cash, Cash Equivalents and Restricted Cash



	June 30, 2020		December 31, 2019
	(In thousands)
Cash and cash equivalents	$	164,091	$	224,502
Restricted cash - current	186		4,302
Restricted cash - long-term	542		542
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	164,819	$	229,346

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

In accordance with 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 $115.2 million and $112.3 million of materials and supplies and $15.1 million and $2.1 million of hydrocarbons as of June 30, 2020 and December 31, 2019, 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 June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	28,147		$	63,165		$	52,518		$	152,279
Revenues from contract with customer - Ghana	64,577			209,469			114,250			328,800
Revenues from contract with customers - U.S. Gulf of Mexico	39,222			129,364			142,674			214,431
Provisional oil sales contracts	(4,632		)	(6,065		)	(4,348		)	(2,787		)
Oil and gas revenue	$	127,314		$	395,933		$	305,094		$	692,723

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Restructuring Charges

The Company accounts for restructuring charges and related termination benefits in accordance with ASC 712—Compensation-Nonretirement Postemployment Benefits. Under this standard, the costs associated with termination benefits are recorded during the period in which the liability is incurred. During the three and six months ended June 30, 2020, we recognized $(0.6) million and $13.3 million, respectively, in restructuring charges for employee severance and related benefit costs incurred as part of a corporate reorganization in Other expenses, net in the consolidated statement of operations.

Concentration of Credit Risk

Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are available, we believe that the loss of our marketing agent and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. 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. For our U.S. Gulf of Mexico operations, crude oil and natural gas are transported to customers using third-party pipelines. For the three months ended June 30, 2020 and 2019, revenue from Phillips 66 Company made up approximately 24% and 22%, respectively, and revenue from Shell Trading (US) Company made up approximately 8% and 9%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment. For the six months ended June 30, 2020 and 2019, revenue from Phillips 66 Company made up approximately 37% and 22%, respectively, and revenue from Shell Trading (US) Company made up approximately 15% and 7%, respectively, of our total consolidated revenue and was included in our U.S. Gulf of Mexico segment.

Recent Accounting Standards

In June 2016, ASU 2016-13, "Measurement of Credit Losses on Financial Instruments," was issued requiring measurement of all expected credit losses for certain types of financial instruments, including trade receivables, held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. This standard was effective January 1, 2020. We assessed all receivable positions for expected credit losses through the implementation of ASU 2016-13, current expected credit loss standard (CECL). Our receivables are collectible in the original term of the underlying agreements and current expected credit losses under the CECL standard are not significant.

In December 2019, the FASB issued ASU 2019-12, “Simplifying the Accounting for Income Taxes”. The amendments in the ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. Early adoption is permitted, however, we do not plan to early adopt ASU 2019-12 at this time. ASU 2019-12 is not expected to have a material impact on our income tax expense.

3. Acquisitions and Divestitures

2020 Transactions

During the second quarter of 2020, Kosmos made a decision to withdraw from our blocks offshore Cote d'Ivoire following our evaluation of seismic data.

In July 2020, we provided notice to Staatsolie that we declined to enter the final exploration phase of the Suriname Block 45 petroleum agreement.

2019 Transactions

During the first quarter of 2019, we agreed a petroleum contract covering offshore Marine XXI block with the national oil company of the Republic of the Congo, Societe Nationale des Petroles du Congo. The petroleum contract was subject to a required governmental approval process before the petroleum contract could be made effective. The petroleum contract had not been approved by the government of the Republic of Congo nor entered into force when, in February 2020, we terminated our interests in the Marine XXI block petroleum contract.

In March 2019, we completed an agreement to acquire Ophir's remaining interest in Block EG-24, offshore Equatorial Guinea, which increased our participating interest to 80% and named Kosmos as operator.

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4. Joint Interest Billings, Related Party Receivables and Notes Receivables

Joint Interest Billings

The Company’s joint interest billings generally 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 consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.

In Ghana, the contractor group funded GNPC’s 5% share of the TEN development costs. The block partners are being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of June 30, 2020 and December 31, 2019, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $9.1 million and $14.0 million, respectively, and the long-term portions were $17.0 million and $16.0 million, respectively.

Notes Receivables

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal which obligate 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 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 June 30, 2020 and December 31, 2019, the balance due from the national oil companies was $71.1 million and $27.4 million, respectively, which is classified as Long-term receivables on our consolidated balance sheets.

5. Property and Equipment

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



	June 30, 2020			December 31, 2019
	(In thousands)
Oil and gas properties:
Proved properties	$	5,129,222		$	4,904,648
Unproved properties	533,393			814,065
Total oil and gas properties	5,662,615			5,718,713
Accumulated depletion	(2,296,869		)	(2,093,962		)
Oil and gas properties, net	3,365,746			3,624,751

Other property	59,686			61,598
Accumulated depreciation	(46,767		)	(44,017		)
Other property, net	12,919			17,581

Property and equipment, net	$	3,378,665		$	3,642,332

We recorded depletion expense of $115.7 million and $144.0 million for the three months ended, June 30, 2020 and 2019, respectively, and $202.9 million and $255.0 million for the six months ended June 30, 2020 and 2019, respectively. 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. Oil prices improved during the three months ended June 30, 2020. During the three months ended June 30, 2020 and 2019, no oil and gas asset impairments were recorded. During the six months ended June 30, 2020 and 2019, we recorded asset impairments totaling $150.8 million and zero, respectively, in our consolidated statement of operations in connection with fair value assessments for oil and gas proved properties in the U.S. Gulf of Mexico.

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6. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the six months ended June 30, 2020. The table excludes $9.6 million in costs that were capitalized and expensed during the same period. During the first quarter of 2020, the exploratory well costs associated with the Greater Tortue Ahmeyim Unit were reclassified to proved property as the execution of the Tortue Phase 1 SPA in February 2020 resulted in recognition of proved undeveloped reserves at that time.



	June 30, 2020
	(In thousands)
Beginning balance	$	445,790
Additions to capitalized exploratory well costs pending the determination of proved reserves	1,140
Reclassification due to determination of proved reserves	(263,849		)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	183,081

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:



	June 30, 2020		December 31, 2019
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	29,616	$	29,121
Exploratory well costs capitalized for a period of one to two years	—		78,245
Exploratory well costs capitalized for a period of three years or greater	153,465		338,424
Ending balance	$	183,081	$	445,790
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	2		3

As of June 30, 2020, 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 and the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal.

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.

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.

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7. Leases

We have commitments under operating leases primarily related to office leases. Our leases have initial lease terms ranging from one year to ten years. Certain lease agreements contain provisions for future rent increases.

The components of lease cost for the three and six months ended June 30, 2020 and 2019 are as follows:



	Three Months Ended June 30,				Six months ended June 30,
	2020		2019		2020		2019
	(In thousands)
Operating lease cost	$	1,899	$	1,602	$	3,157	$	3,009
Short-term lease cost(1)	2,434		582		12,802		587
Total lease cost	$	4,333	$	2,184	$	15,959	$	3,596

__________________________________


(1)	Includes $2.3 million and zero during the three months ended June 30, 2020 and 2019, respectively, and $12.2 million and zero during the six months ended June 30, 2020 and 2019, respectively, of costs associated with short-term drilling contracts.

Other information related to operating leases at June 30, 2020 and 2019, is as follows:



	June 30, 2020			December 31, 2019
(In thousands, except lease term and discount rate)
Balance sheet classifications
Other assets (right-of-use assets)	$	18,775		$	20,008
Accrued liabilities (current maturities of leases)	2,005			1,139
Other long-term liabilities (non-current maturities of leases)	21,078			22,240

Weighted average remaining lease term	8.4 years			8.8 years

Weighted average discount rate	9.9		%	9.8		%

The table below presents supplemental cash flow information related to leases during the six months ended June 30, 2020 and 2019:



	Six Months Ended June 30,
	2020		2019
	(In thousands)
Operating cash flows for operating leases	$	1,909	$	1,750
Investing cash flows for operating leases(1)	12,225		—

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(1)	Represents costs associated with short-term drilling contracts.

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Future minimum rental commitments under our leases at June 30, 2020, are as follows:



	Operating Leases(1)
	(In thousands)
2020(2)	$	2,061
2021	4,174
2022	4,237
2023	4,301
2024	3,464
Thereafter	16,041
Total undiscounted lease payments	$	34,278
Less: Imputed interest	(11,195		)
Total lease liabilities	$	23,083

__________________________________


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


(2)	Represents payments for the period from July 1, 2020 through December 31, 2020.

8. Debt



	June 30, 2020			December 31, 2019
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,450,000		$	1,400,000
Corporate Revolver	100,000			—
Senior Notes	650,000			650,000
Total	2,200,000			2,050,000
Unamortized deferred financing costs and discounts(1)	(36,347		)	(41,937		)
Total debt, net	2,163,653			2,008,063
Less: Current maturities of long-term debt	(56,000		)	—
Long-term debt, net	$	2,107,653		$	2,008,063

__________________________________


(1)	Includes $27.8 million and $32.8 million of unamortized deferred financing costs related to the Facility as of June 30, 2020 and December 31, 2019, respectively; $8.5 million and $9.1 million of unamortized deferred financing costs and discounts related to the Senior Notes as of June 30, 2020 and December 31, 2019, respectively.

Facility

In April 2020, following the lenders' annual redetermination, the available borrowing base and Facility size were both reduced from $1.6 billion to $1.5 billion. In addition, as part of the redetermination process, the Company agreed to conduct an additional redetermination in September 2020. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of June 30, 2020, borrowings under the Facility totaled $1.45 billion and the undrawn availability under the facility was $0.05 billion.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of June 30, 2020, we had no letters of credit issued under the Facility.

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As 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. In addition, as part of the amendment to relax the debt cover ratio, we agreed to include the advanced amounts under the Production Prepayment Agreement as part of the debt cover ratio calculation. We were in compliance with the financial covenants as of the most recent assessment date. The Facility contains customary cross default provisions.

Corporate Revolver

In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points 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 June 30, 2020, there were $100.0 million in outstanding borrowings under the Corporate Revolver and the undrawn availability was $300.0 million. As of June 30, 2020, we have $5.0 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term.

As 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. In addition, as part of the amendment to relax the debt cover ratio, we agreed to include the advanced amounts under the Production Prepayment Agreement as part of the debt cover ratio calculation. We were in compliance with the financial covenants as of the most recent assessment date. The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

Our revolving letter of credit facility agreement (“LC Facility”) expired in July 2019.In May 2020, the remaining five outstanding letters of credit under the LC Facility totaling $3.1 million were released and the LC Facility was subsequently terminated in June 2020.

In 2019, we issued two letters of credit totaling $20.4 million under a new letter of credit arrangement, which does not currently require cash collateral.

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 commissions and other expenses. We used the net proceeds to redeem all of the Senior Secured Notes, 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 Senior Notes.

The Senior Notes mature on April 4, 2026. Interest is payable in arrears each April 4 and October 4, commencing on October 4, 2019. The 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 rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company'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 Senior Notes as of March 31, 2020. The Senior Notes contain customary cross default provisions.

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At June 30, 2020, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:



	Payments Due by Year
	Total		2020(2)		2021		2022		2023		2024		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,200,000	$	—	$	56,000	$	422,571	$	428,571	$	428,572	$	864,286

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(1)

Includes the scheduled principal maturities for the $650.0 million aggregate principal amount of Senior Notes and borrowings under the Facility and Corporate Revolver. The scheduled maturities of debt related to the Facility as of June 30, 2020 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 July 1, 2020 through December 31, 2020.

Interest and other financing costs, net

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
	(In thousands)
Interest expense	$	28,504		$	38,450		$	60,270		$	76,622
Amortization—deferred financing costs	2,192			2,302			4,475			4,689
Loss on extinguishment of debt	2,215			24,794			2,215			24,794
Capitalized interest	(5,729		)	(7,002		)	(12,256		)	(14,253		)
Deferred interest	1,182			433			1,496			1,270
Interest income	(1,023		)	(591		)	(2,102		)	(1,243		)
Other, net	933			1,417			2,011			2,965
Interest and other financing costs, net	$	28,274		$	59,803		$	56,109		$	94,844

9. Production Prepayment Agreement, net



	June 30, 2020			December 31, 2019
	(In thousands)
Production prepayment	$	50,000		$	—
Unamortized deferred financing costs	(667		)	—
Production prepayment agreement, net	$	49,333		$	—

In June 2020, the Company received $50 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 Production Prepayment Agreement is for up to $200 million of crude oil sales, with an additional $100 million committed by Trafigura in addition to the $50 million received in June 2020. The Company will sell to Trafigura a specified volume of crude oil each month as defined in the Volume Model, which is expected to be finalized in the third quarter of 2020 in accordance with the terms of the Production Prepayment Agreement (estimated at approximately 2 million barrels total), for no more than 60 months following the funding in June 2020, such final delivery date being the "Final Delivery Date," provided, however, if the market value of the crude oil volumes delivered prior to the Final Delivery Date is equal to $57.5 million, then the Company's obligation would be considered fully satisfied. Under the Production Prepayment Agreement, upon the satisfaction of certain conditions provided in the Production Prepayment Agreement, the Company may elect for Trafigura to prepay for two additional tranches of crude oil in the amount of $100 million

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on September 30, 2020 and $50 million on or before March 31, 2021. If the Company makes such election, the total volume of crude oil to be sold will be adjusted accordingly.

Financing costs includes the applicable margin of 5%; LIBOR; and mandatory costs. We recognize interest expense in accordance with ASC 835 — Interest, which requires interest expense to be recognized using the effective interest method. The total financing costs associated with the Production Prepayment Agreement are based on the estimated market value of the crude oil to be delivered to Trafigura compared to the cash proceeds received, which is expected to be $7.5 million as of June 30, 2020.

As a condition to Trafigura’s obligations, the Company will ‎grant a mortgage interest in certain specified production fields located in the U.S. Gulf of Mexico.

During the term of the Production Prepayment Agreement, the Company will be required to ‎maintain certain ongoing ratios as defined in the Production Prepayment Agreement. We were in compliance with the financial covenants contained in the Production Prepayment Agreement as of June 30, 2020, which requires the maintenance of:


•	the Guarantor Liquidity Ratio (as defined in the glossary), not less than 1.20x and


•	the GoM Liquidity Ratio (as defined in the glossary), not less than 1.50x

At June 30, 2020, based on quoted future market prices, the value of the estimated volumes to be delivered under the Production Prepayment Agreement during the five fiscal year periods and thereafter are as follows:



	Payments Due by Year
	Total		2020(2)		2021		2022		2023		2024		Thereafter
	(In thousands)
Production Prepayment Agreement(1)	$	50,000	$	—	$	15,729	$	30,799	$	3,472	$	—	$	—

__________________________________


(1)	Any increases or decreases in future market prices would impact the scheduled maturities during the next five years and thereafter.


(2)	Represents payments for the period July 1, 2020 through December 31, 2020.

10. 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 June 30, 2020. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.



				Weighted Average Price per Bbl
				Net Deferred
				Premium
Term	Type of Contract	Index	MBbl	Payable/(Receivable)			Swap		Sold Put		Floor		Ceiling		Purchased Call
2020:
Jul — Dec	Swaps	Dated Brent	5,275	$	—		$	42.67	$	—	$	—	$	—	$	—
Jul — Dec	Swaps	Argus LLS	3,000	—			29.98		—		—		—		—
Jul — Dec	Call spreads	NYMEX WTI	(1)	1.20			—		—		—		45.00		35.00
Jul — Dec	Swaps with sold puts	Dated Brent	333	—			35.00		25.00		—		—		—
Jul — Dec	Three-way collars	Dated Brent	1,000	—			—		25.00		32.50		40.00		—
Jul — Dec	Sold calls(2)	Dated Brent	4,750	(0.19		)	—		—		—		80.83		—
2021:
Jan — Dec	Swaps with sold puts	Dated Brent	5,000	$	—		$	54.70	$	43.50	$	—	$	—	—
Jan — Dec	Three-way collars	Dated Brent	1,000	1.00			—		30.00		40.00		55.40		—
Jan — Dec	Sold calls(2)	Dated Brent	7,000	—			—		—		—		70.09		—
2022:
Jan — Dec	Sold calls(2)	Dated Brent	1,581	—			—		—		—		60.00		—

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(1)	Added call spreads on 1.0 million barrels to open upside for U.S. Gulf of Mexico production.


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

In April 2020, we restructured the majority of our May 2020 through December 2020 derivative contracts, whereby we converted the existing hedges into 7.0 MMBbls of Dated Brent swap contracts with an average fixed price of $42.67 per barrel. In July 2020, we entered into Dated Brent costless three-way collar contracts for 1.0 MMBbl from January 2021 through December 2021 with a sold put price of $30.00 per barrel, a floor price of $40.00 per barrel and a ceiling price of $55.00 per barrel. The following tables disclose the Company’s derivative instruments as of June 30, 2020 and December 31, 2019, and gain/(loss) from derivatives during the three and six months ended June 30, 2020 and 2019, respectively:



		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	June 30, 2020			December 31, 2019
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity	Derivatives assets—current	$	30,289		$	12,856
Provisional oil sales	Receivables: Oil Sales	—			(3,287		)
Commodity	Derivatives assets—long-term	11,271			2,302
Derivative liabilities:
Commodity	Derivatives liabilities—current	(43,974		)	(8,914		)
Commodity	Derivatives liabilities—long-term	(9,306		)	(11,478		)
Total derivatives not designated as hedging instruments		$	(11,720	)	$	(8,521	)

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		Amount of Gain/(Loss)						Amount of Gain/(Loss)
		Three Months Ended						Six Months Ended
		June 30,						June 30,
Type of Contract	Location of Gain/(Loss)	2020			2019			2020			2019
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	(4,632	)	$	(6,064	)	$	(4,348	)	$	(2,786	)
Commodity	Derivatives, net	(100,075		)	14,185			35,963			(62,900		)
Total derivatives not designated as hedging instruments		$	(104,707	)	$	8,121		$	31,615		$	(65,686	)

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

Offsetting of Derivative Assets and Derivative Liabilities

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of June 30, 2020 and December 31, 2019, 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.

11. 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.


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

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2020 and December 31, 2019, 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)
June 30, 2020
Assets:
Commodity derivatives	$	—	$	41,560		$	—	$	41,560
Provisional oil sales	—		—			—		—
Liabilities:
Commodity derivatives	—		(53,280		)	—		(53,280		)
Total	$	—	$	(11,720	)	$	—	$	(11,720	)
December 31, 2019
Assets:
Commodity derivatives	$	—	$	15,158		$	—	$	15,158
Provisional oil sales	—		(3,287		)	—		(3,287		)
Liabilities:
Commodity derivatives	—		(20,392		)	—		(20,392		)
Total	$	—	$	(8,521	)	$	—	$	(8,521	)

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

Commodity Derivatives

Our commodity derivatives represent crude oil 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 10 — 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 and Production Prepayment Agreement

The following table presents the carrying values and fair values at June 30, 2020 and December 31, 2019:



	June 30, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	643,028	$	580,554	$	642,550	$	664,957
Production Prepayment Agreement	50,000		57,500		—		—
Corporate Revolver	100,000		100,000		—		—
Facility	1,450,000		1,450,000		1,400,000		1,400,000
Total	$	2,243,028	$	2,188,054	$	2,042,550	$	2,064,957

The carrying value of our Senior Notes and Production Prepayment Agreement represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The fair value of the Production Prepayment Agreement represents the estimated value of the crude oil barrels in the Volume Model agreed to be delivered based on quoted market prices which results in a Level 2 fair value measurement. At June 30, 2020, the value of the crude oil volumes to be delivered exceeds $57.5 million prior to the Final Delivery Date, which results in the Company's obligation being fully satisfied when delivered. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

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 against earnings of $150.8 million, reducing the carrying value of the properties to their estimated fair values of $243.7 million. As part of our impairment analysis, the average per barrel Dated Brent price of third-party industry forecasts used for purposes of determining discounted future cash flows ranged from the mid-$30s in 2020 increasing to the mid-$50s over several years. The expected future cash flows were discounted using a rate of approximately 10 percent, which the Company believes is a market-based weighted average cost of capital for industry peers determined appropriate at the time of the valuation. These impairment charges are included in Impairments of long-lived assets on the consolidated statement of operations. The Company did not recognize additional impairment of proved oil and gas properties during the three months ended June 30, 2020 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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12. 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 $8.3 million and $9.5 million during the three months ended June 30, 2020 and 2019, respectively, and $17.7 million and $17.9 million during the six months ended June 30, 2020 and 2019, respectively. The total tax benefit for the three months ended June 30, 2020 and 2019 was $1.7 million and $1.5 million, respectively, and $3.8 million and $2.8 million during the six months ended June 30, 2020 and 2019, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $0.2 million and nil for the three months ended June 30, 2020 and 2019, respectively, and $1.1 million and $1.2 million during the six months ended June 30, 2020 and 2019, respectively. The fair value of awards vested during the three months ended June 30, 2020 and 2019 was $0.4 million and $0.8 million, respectively, and $25.8 million and $14.0 million during the six months ended June 30, 2020 and 2019, 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 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 June 30, 2020:



			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, 2019	4,731		$	5.71	7,798		$	8.42
Granted(1)	3,474		5.49		3,392		8.37
Forfeited(1)	(901	)	6.17		(476	)	8.02
Vested	(2,067	)	5.86		(2,582	)	9.47
Outstanding at June 30, 2020	5,237		5.41		8,132		8.11

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(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 June 30, 2020, total equity-based compensation to be recognized on unvested restricted stock units is $41.6 million over a weighted average period of 2.02 years. In March 2018, 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 General Meeting in June 2018. The LTIP provides for the issuance of 50.5 million shares pursuant to awards under the plan. At June 30, 2020, the Company had approximately 6.0 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 $12.96 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 44.0% 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 0.8% 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 $0.045 to $0.050.

13. Income Taxes

We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors, which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned, and the tax laws in those jurisdictions. We evaluate our estimated annual effective income tax rate each

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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.

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

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. For the three and six months ended June 30, 2020, we increased our valuation allowance associated with our U.S. deferred tax assets by $16.7 million and $86.1 million, respectively, resulting in $30.9 million of net U.S. deferred tax expense. The valuation allowance was necessary due to the recent decline in oil prices and the impact on our expected ability to utilize U.S. tax losses in the future.

In March 2020, the Coronavirus Aid, Relief, and Economic Security ACT ("CARES Act") became law. Among other things, the CARES Act permits taxpayers to carry back U.S. taxable losses generated during tax years 2018 through 2020 to the five tax years preceding the loss year to obtain tax refunds. Certain of our U.S. legal entities qualify for such relief and we recorded a current tax benefit of $4.9 million during the first quarter of 2020, with a total $12.2 million income tax refund claim. Other provisions of the CARES Act are not expected to have a material impact to our tax expense.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
	(In thousands)
United States	$	(79,703	)	$	(18,499	)	$	(269,840	)	$	(74,240	)
Foreign—other	(167,113		)	67,938			(94,200		)	62,099
Income (loss) before income taxes	$	(246,816	)	$	49,439		$	(364,040	)	$	(12,141	)

For the three months ended, June 30, 2020 and 2019, our effective tax rate was 19% and 66%, respectively. For the six months ended, June 30, 2020 and 2019, our effective tax rate was 5% and 197%, respectively.

For the three and six months ended June 30, 2020, our overall effective tax rate was impacted by deferred tax expense related to valuation allowances on certain U.S. deferred tax assets and by a current tax benefit related to certain U.S. tax losses incurred in 2018 and carried back to years with a higher income tax rate. Additionally, for the three and six months ended June 30, 2020 and 2019, 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, non-deductible and non-taxable items associated with our U.S., Ghanaian, and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are the United States, Ghana and Equatorial Guinea. The Company is open to tax examinations in the United States for federal income tax return years 2016 through 2019 and in Ghana to federal income tax return years 2014 through 2019.

As of June 30, 2020, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

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14. Net Income (Loss) Per Share

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



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2020			2019		2020			2019
	(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders	$	(199,391	)	$	16,837	$	(382,158	)	$	(36,069	)
Denominator:
Weighted average number of shares outstanding:
Basic	405,195			401,323		404,990			401,244
Restricted stock awards and units(1)(2)	—			6,907		—			—
Diluted	405,195			408,230		404,990			401,244
Net income (loss) per share:
Basic	$	(0.49	)	$	0.04	$	(0.94	)	$	(0.09	)
Diluted	$	(0.49	)	$	0.04	$	(0.94	)	$	(0.09	)

__________________________________


(1)	We excluded outstanding restricted stock awards and units of 11.6 million and 1.1 million for the three months ended June 30, 2020 and 2019, respectively, and 11.3 million and 12.9 million for the six months ended June 30, 2020 and 2019, respectively, from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.

15. Commitments and Contingencies

From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect 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 each of Sao Tome and Principe and Namibia and two exploration wells in Mauritania. In Sao Tome and Principe, we also have 3D seismic acquisition requirements of approximately 8,800 square kilometers, and in Mauritania we have 100 line km requirement for controlled source electromagnetic data acquisition. In South Africa we have 2D seismic acquisition requirements of approximately 500 line kilometers.

Performance Obligations

As of June 30, 2020 and December 31, 2019, the Company had performance bonds totaling $208.7 million for our supplemental bonding requirements stipulated by the BOEM and $7.2 million to other operators 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 June 30, 2020 and December 31, 2019, 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 COVID-19 pandemic, the Board of Directors decided to suspend the dividend.

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16. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:



	June 30, 2020		December 31, 2019
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	83,052	$	152,490
Revenue payable	22,028		32,482
Current asset retirement obligations	2,810		4,527
General and administrative expenses	3,518		44,575
Interest	22,953		33,584
Income taxes	56,649		103,566
Taxes other than income	3,230		3,375
Derivatives	5,340		4,837
Other	3,695		1,268
	$	203,275	$	380,704

Asset Retirement Obligations

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



	June 30, 2020
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	235,053
Liabilities incurred during period	—
Liabilities settled during period	(3,905		)
Revisions in estimated retirement obligations	2,138
Accretion expense	9,369
Ending asset retirement obligations	$	242,655

Facilities Insurance Modifications, Net

Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility, net of related insurance reimbursements. During the three months ended June 30, 2020 and 2019, we incurred approximately $0.1 million and $11.2 million, respectively in expenditures offset by approximately zero and $8.9 million, respectively, in insurance recoveries. During the six months ended, June 30, 2020 and 2019, we incurred approximately $8.1 million and $22.2 million, respectively, in expenditures offset by approximately zero and $39.9 million, respectively, in insurance recoveries.

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Other Expenses, Net

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020		2019
	(In thousands)
Loss on disposal of inventory	$	361		$	—		$	1,828	$	187
(Gain) loss on ARO liability settlements	(28		)	(5		)	2,122		1,913
Restructuring charges	(575		)	—			13,340		—
Other, net	1,470			(1,788		)	7,867		(1,774		)
Other expenses, net	$	1,228		$	(1,793	)	$	25,157	$	326

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

17. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration and development of oil and gas. At June 30, 2020, 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 ("CODM") 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 June 30, 2020
Revenues and other income:
Oil and gas revenue	$	61,192		$	26,901		$	—		$	39,221		$	—		$	—		$	127,314
Other income, net	—			—			—			4			121,264			(121,268		)	—
Total revenues and other income	61,192			26,901			—			39,225			121,264			(121,268		)	127,314
Costs and expenses:
Oil and gas production	46,568			25,414			—			16,765			—			—			88,747
Facilities insurance modifications, net	52			—			—			—			—			—			52
Exploration expenses	13			2,117			985			6,594			6,002			—			15,711
General and administrative	3,132			1,222			2,176			2,849			28,217			(19,410		)	18,186
Depletion, depreciation and amortization	64,917			19,409			16			36,880			635			—			121,857
Impairment of long-lived assets	—			—			—			—			—			—			—
Interest and other financing costs, net(1)	13,322			(331		)	(6,222		)	2,991			20,297			(1,783		)	28,274
Derivatives, net	—			—			—			—			100,075			—			100,075
Other expenses, net	54,048			6,379			(322		)	40,093			1,105			(100,075		)	1,228
Total costs and expenses	182,052			54,210			(3,367		)	106,172			156,331			(121,268		)	374,130
Income (loss) before income taxes	(120,860		)	(27,309		)	3,367			(66,947		)	(35,067		)	—			(246,816		)
Income tax expense (benefit)	(44,051		)	(13,258		)	—			(1		)	9,885			—			(47,425		)
Net income (loss)	$	(76,809	)	$	(14,051	)	$	3,367		$	(66,946	)	$	(44,952	)	$	—		$	(199,391	)

Consolidated capital expenditures	$	8,590		$	9,335		$	2,202		$	39,897		$	6,360		$	—		$	66,384

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	Ghana			Equatorial Guinea			Mauritania/Senegal			U.S. Gulf of Mexico			Corporate & Other			Eliminations			Total
	(In thousands)
Six months ended June 30, 2020
Revenues and other income:
Oil and gas revenue	$	110,900		$	51,520		$	—		$	142,674		$	—		$	—		$	305,094
Other income, net	1			—			—			451			9,255			(9,706		)	1
Total revenues and other income	110,901			51,520			—			143,125			9,255			(9,706		)	305,095
Costs and expenses:
Oil and gas production	64,610			36,889			—			48,851			—			—			150,350
Facilities insurance modifications, net	8,090			—			—			—			—			—			8,090
Exploration expenses	98			4,836			4,459			20,561			30,362			—			60,316
General and administrative	7,022			2,960			4,285			6,853			60,079			(42,102		)	39,097
Depletion, depreciation and amortization	84,648			28,303			31			100,714			1,463			—			215,159
Impairment of long-lived assets	—			—			—			150,820			—			—			150,820
Interest and other financing costs, net(1)	28,153			(700		)	(12,848		)	7,680			37,391			(3,567		)	56,109
Derivatives, net	—			—			—			—			(35,963		)	—			(35,963		)
Other expenses, net	(62,324		)	(9,377		)	2,471			43,745			14,679			35,963			25,157
Total costs and expenses	130,297			62,911			(1,602		)	379,224			108,011			(9,706		)	669,135
Income (loss) before income taxes	(19,396		)	(11,391		)	1,602			(236,099		)	(98,756		)	—			(364,040		)
Income tax expense (benefit)	(5,830		)	(8,670		)	—			30,902			1,716			—			18,118
Net income (loss)	$	(13,566	)	$	(2,721	)	$	1,602		$	(267,001	)	$	(100,472	)	$	—		$	(382,158	)

Consolidated capital expenditures	$	25,076		$	16,106		$	5,323		$	78,551		$	25,795		$	—		$	150,851

As of June 30, 2020
Property and equipment, net	$	1,429,160		$	453,178		$	451,140		$	1,018,586		$	26,601		$	—		$	3,378,665
Total assets	$	1,567,529		$	692,283		$	650,351		$	3,067,724		$	12,404,285		$	(14,395,681	)	$	3,986,491

______________________________________


(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 June 30, 2019
Revenues and other income:
Oil and gas revenue	$	202,085		$	64,484		$	—		$	129,364		$	—		$	—		$	395,933
Other income, net	1			—			—			124			19,079			(19,203		)	1
Total revenues and other income	202,086			64,484			—			129,488			19,079			(19,203		)	395,934
Costs and expenses:
Oil and gas production	44,954			16,670			—			29,353			—			—			90,977
Facilities insurance modifications, net	2,278			—			—			—			—			—			2,278
Exploration expenses	56			2,472			2,043			11,015			14,319			—			29,905
General and administrative	6,002			1,539			1,540			4,893			44,313			(30,215		)	28,072
Depletion, depreciation and amortization	75,898			16,287			15			58,215			1,023			—			151,438
Interest and other financing costs, net(1)	19,026			—			(6,524		)	5,642			43,443			(1,784		)	59,803
Derivatives, net	—			—			—			(1,390		)	(12,795		)	—			(14,185		)
Other expenses, net	(12,982		)	(2,583		)	412			553			11			12,796			(1,793		)
Total costs and expenses	135,232			34,385			(2,514		)	108,281			90,314			(19,203		)	346,495
Income (loss) before income taxes	66,854			30,099			2,514			21,207			(71,235		)	—			49,439
Income tax expense (benefit)	24,683			11,762			—			4,439			(8,282		)	—			32,602
Net income (loss)	$	42,171		$	18,337		$	2,514		$	16,768		$	(62,953	)	$	—		$	16,837

Consolidated capital expenditures	$	33,496		$	6,115		$	4,039		$	41,177		$	15,858		$	—		$	100,685

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	Ghana			Equatorial Guinea			Mauritania/Senegal			U.S. Gulf of Mexico			Corporate & Other			Eliminations			Total
	(In thousands)
Six months ended June 30, 2019
Revenues and other income:
Oil and gas revenue	$	325,003		$	153,289		$	—		$	214,431		$	—		$	—		$	692,723
Other income, net	1			—			—			259			91,888			(92,147		)	1
Total revenues and other income	325,004			153,289			—			214,690			91,888			(92,147		)	692,724
Costs and expenses:
Oil and gas production	75,010			39,276			—			56,490			—			—			170,776
Facilities insurance modifications, net	(17,743		)	—			—			—			—			—			(17,743		)
Exploration expenses	107			5,643			8,485			22,209			23,805			—			60,249
General and administrative	11,958			3,584			3,827			12,286			88,519			(56,194		)	63,980
Depletion, depreciation and amortization	130,761			39,304			31			97,409			2,028			—			269,533
Interest and other financing costs, net(1)	39,679			—			(13,317		)	11,571			60,478			(3,567		)	94,844
Derivatives, net	—			—			—			30,513			32,387			—			62,900
Other expenses, net	32,118			(2,243		)	641			2,145			51			(32,386		)	326
Total costs and expenses	271,890			85,564			(333		)	232,623			207,268			(92,147		)	704,865
Income (loss) before income taxes	53,114			67,725			333			(17,933		)	(115,380		)	—			(12,141		)
Income tax expense (benefit)	19,700			27,293			—			(3,766		)	(19,299		)	—			23,928
Net income (loss)	$	33,414		$	40,432		$	333		$	(14,167	)	$	(96,081	)	$	—		$	(36,069	)

Consolidated capital expenditures	$	68,463		$	21,051		$	6,290		$	87,059		$	28,050		$	—		$	210,913

As of June 30, 2019
Property and equipment, net	$	1,643,410		$	460,679		$	422,539		$	1,281,439		$	39,506		$	—		$	3,847,573
Total assets	$	1,872,202		$	498,195		$	546,454		$	3,343,917		$	12,051,009		$	(13,846,043	)	$	4,465,734

______________________________________


(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.



	Six Months Ended June 30,
	2020			2019
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	135,242		$	153,268
Other property	1,536			5,230
Adjustments:
Changes in capital accruals	(20,392		)	13,684
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	39,461			53,150
Capitalized interest	(12,256		)	(14,253		)
Other	7,260			(166		)
Total consolidated capital expenditures	$	150,851		$	210,913

______________________________________


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

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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, 2019, 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 exploration program balanced between proven basin infrastructure-led exploration (Equatorial Guinea and U.S. Gulf of Mexico), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Namibia, Sao Tome and Principe, and South Africa).

The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in increased 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 decreased demand for oil, which has also resulted in significant declines in oil prices. The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on oil prices. Due to the COVID-19 pandemic, our operations have been impacted as follows:

•

Delay to the installation of the Ghana Jubilee catenary anchor leg mooring (“CALM”) buoy. The Government of Ghana implemented certain travel restrictions pertaining to its borders. The contractor responsible for the installation and commissioning of the Jubilee CALM buoy decided to suspend operations and demobilize from Ghana. Kosmos expects the contractor to return to Ghana this year to complete installation and commissioning of the CALM buoy. As a result of the delay, the Jubilee joint venture is expected to continue to incur an estimated $6 million (gross) per month conducting ship to ship transfer operations until the CALM buoy is installed and commissioned.


•	Deferral of the current Ghana drilling program associated with the termination of the Ghana drilling rig contract. The Company did not incur material costs associated with the termination of the drilling contract.


•	Elected to defer completion operations on the Kodiak in-fill well drilled during 2020 in the U.S. Gulf of Mexico. Additionally, our U.S. Gulf of Mexico infrastructure led exploration (ILX) program was suspended. The Company did not incur material costs associated with the decision not to extend the drilling contract.


•	Suspension of the 2020-2021 Equatorial Guinea drilling program and ESP program. The Company did not incur material costs associated with the suspension of the programs.

•

Delay of the construction of the Greater Tortue Ahmeyim Phase 1 development project by approximately 12 months, with first gas now expected in the first half of 2023. Phase 1 of the project is currently approximately 40% complete. This delay is expected to result in a significant reduction in budgeted spend in 2020 as activity and milestone payments are delayed. With the re-phasing of the project timeline, the partnership has approved a revised budget and, as a result, the carry of our capital obligations is expected to be extended through the end of this year. In addition, we continue with the Tortue sell down process to support a self-funded gas business.

•

Government of Sao Tome and Principe implemented certain travel regulations restricting international travelers from entering the country. These restrictions made it impossible for the Company to safely manage the seismic acquisition in Blocks 10 and 13. As the technical operator of the seismic acquisition, the Company declared force majeure on the seismic acquisition contract and terminated it. Thereafter, BP, as operator of Blocks 10 and 13, declared force majeure on the blocks.


•	Delayed expected spud date of the Jaca exploration well in Sao Tome Block 6 from the fourth quarter of 2020 to the second half of 2021.

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•	Suspension of the quarterly dividend by the Board of Directors.


•	During the first quarter of 2020, reduced Company headcount resulting in restructuring charges for employee severance and related benefits totaling approximately $13.3 million during the six months ended June 30, 2020.


•	During the first quarter of 2020, recorded asset impairments totaling $150.8 million during the three months ended March 31, 2020 primarily as a result of lower oil prices arising from the COVID-19 pandemic. The Company did not recognize additional impairment of proved oil and gas properties during the three months ended June 30, 2019 as no impairment indicators were identified.

Recent Developments

Ghana

Jubilee

During the second quarter of 2020, Jubilee production averaged approximately 90,000 Bopd (gross) with consistent water injection and gas offtake since the work to enhance gas handling capacity was successfully performed by the operator during the first quarter of 2020.

TEN

During the second quarter of 2020, TEN production averaged approximately 50,000 Bopd (gross). In the third quarter of 2020, Kosmos expects the NT-09 well to be brought online.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 20,200 Boepd (net) for the second quarter of 2020, including the impact of approximately 6,000 Boepd shut-in during the quarter.

As a result of market conditions in the second quarter, the operator of the Delta House platform in the U.S. Gulf of Mexico shut-in the facility during the month of May 2020 and accelerated planned maintenance. The shut-ins were primarily limited to May 2020 and all shut-in fields were brought back online by early June 2020.

In the first half of 2020, we successfully drilled a Kodiak development well located in Mississippi Canyon Block 727 (29.1% working interest). The well is a subsea tieback, which is expected to be brought online through existing infrastructure to the Devils Tower SPAR in the first half of 2021.

In Q2 2020, Tornado 4 development well located in Green Canyon Block 280 (35.0% working interest) was successfully drilled by the operator. Kosmos expects the well to be brought online in the second half of 2020, produce for approximately 6 months, and then be converted to a waterflood well.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 34,000 Bopd (gross) in the second quarter of 2020.

Mauritania and Senegal

Greater Tortue Ahmeyim Unit

The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the Company's independent reserve auditor, Ryder Scott, LP.

Suriname

In July 2020, we provided notice to Staatsolie that we declined to enter the final exploration phase of the Suriname Block 45 petroleum agreement.

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Sao Tome and Principe

In July 2020, we received approval for a one year extension to the current exploration phase for Block 11 offshore Sao Tome and Principe to July 2022.

Cote d'Ivoire

In May 2020, a withdrawal notice for our offshore blocks CI-526, CI-602, CI-603, CI-707, and CI-708 offshore Cote d'Ivoire was issued to partners and the Government of Cote d'Ivoire.

Republic of the Congo

In February 2020, notice of withdrawal from the approval process awarding Kosmos' interest in the offshore Marine XXI block was issued to the Republic of the Congo.

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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 six months ended June 30, 2020 and 2019 are included in the following tables:



	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	5,751		5,851		9,202		10,541
Gas (MMcf)	1,303		1,663		3,284		3,464
NGL (MBbl)	142		139		335		251
Total (MBoe)	6,110		6,267		10,084		11,369
Total (Boepd)	67,145		68,870		55,408		62,814

Revenues:
Oil sales	$	124,813	$	389,286	$	296,729	$	680,150
Gas sales	2,113		4,145		5,832		7,807
NGL sales	388		2,502		2,533		4,766
Total revenues	$	127,314	$	395,933	$	305,094	$	692,723

Average oil sales price per Bbl	$	21.70	$	66.53	$	32.25	$	64.52
Average gas sales price per Mcf	1.62		2.49		1.78		2.25
Average NGL sales price per Bbl	2.73		18.01		7.56		19.00
Average total sales price per Boe	20.84		63.18		30.25		60.93

Costs:
Oil and gas production, excluding workovers	$	87,726	$	85,351	$	145,143	$	158,066
Oil and gas production, workovers	1,021		5,626		5,207		12,710
Total oil and gas production costs	$	88,747	$	90,977	$	150,350	$	170,776

Depletion, depreciation and amortization	$	121,857	$	151,438	$	215,159	$	269,533

Average cost per Boe:
Oil and gas production, excluding workovers	$	14.36	$	13.62	$	14.39	$	13.90
Oil and gas production, workovers	0.17		0.90		0.52		1.12
Total oil and gas production costs	14.53		14.52		14.91		15.02

Depletion, depreciation and amortization	19.94		24.16		21.34		23.71
Total	$	34.47	$	38.68	$	36.25	$	38.73

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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 June 30, 2020:



	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	—	—	7	1.19
Equatorial Guinea
Block S	—	—	—	—	1	0.40	—	—
U.S. Gulf of Mexico
Tornado 4	—	—	1	0.35	—	—	—	—
Kodiak 727 #3	—	—	—	—	—	—	1	0.29
Mauritania / Senegal
Mauritania C8	—	—	—	—	2	0.56	—	—
Greater Tortue Ahmeyim Unit	—	—	—	—	3	0.80	1	0.27
Senegal Cayar Profond	—	—	—	—	3	0.90	—	—
Total	—	—	2	0.52	9	2.66	18	3.92

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 June 30, 2020 compared to three months ended June 30, 2019



	Three Months Ended
	June 30,						Increase
	2020			2019			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	127,314		$	395,933		$	(268,619	)
Other income, net	—			1			(1		)
Total revenues and other income	127,314			395,934			(268,620		)
Costs and expenses:
Oil and gas production	88,747			90,977			(2,230		)
Facilities insurance modifications, net	52			2,278			(2,226		)
Exploration expenses	15,711			29,905			(14,194		)
General and administrative	18,186			28,072			(9,886		)
Depletion, depreciation and amortization	121,857			151,438			(29,581		)
Impairment of long-lived assets	—			—			—
Interest and other financing costs, net	28,274			59,803			(31,529		)
Derivatives, net	100,075			(14,185		)	114,260
Other expenses, net	1,228			(1,793		)	3,021
Total costs and expenses	374,130			346,495			27,635
Income (loss) before income taxes	(246,816		)	49,439			(296,255		)
Income tax expense (benefit)	(47,425		)	32,602			(80,027		)
Net income (loss)	$	(199,391	)	$	16,837		$	(216,228	)

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Oil and gas revenue. Oil and gas revenue decreased by $268.6 million as a result of lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic. We sold 6,110 MBoe at an average realized price per barrel equivalent of $20.84 during the three months ended June 30, 2020 and 6,267 MBoe at an average realized price per barrel equivalent of $63.18 during the three months ended June 30, 2019.

Oil and gas production. Oil and gas production costs decreased by $2.2 million during the three months ended June 30, 2020, as compared to the three months ended June 30, 2019 as a result of lower workover costs in the current period.

Facilities insurance modifications, net. During the three months ended June 30, 2020, we incurred $0.1 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue versus $11.2 million during the three months ended June 30, 2019. During the three months ended June 30, 2020 and 2019, these costs were offset by zero and $8.9 million, respectively, of hull and machinery insurance proceeds.

Exploration expenses. Exploration expenses decreased by $14.2 million during the three months ended June 30, 2020, as compared to the three months ended June 30, 2019. The decrease is primarily a result of lower seismic costs incurred in 2020 versus the prior period related to the U.S. Gulf of Mexico business unit.

General and administrative. General and administrative costs decreased by $9.9 million during the three months ended June 30, 2020, as compared to the three months ended June 30, 2019 primarily as a result of headcount and other cost reductions.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $29.6 million during the three months ended June 30, 2020, as compared with the three months ended June 30, 2019 primarily as a result of increased reserves recorded in the fourth quarter of 2019 and a lower cost basis in the U.S. Gulf of Mexico associated with an impairment recorded in the first quarter of 2020.

Interest and other financing costs, net. Interest and other financing costs, net decreased $31.5 million primarily a result of the $24.8 million loss on extinguishment of debt primarily associated with the refinancing of our senior notes recorded during the second quarter of 2019 and lower interest rates during the current period.

Derivatives, net. During the three months ended June 30, 2020 and 2019, we recorded a loss of $100.1 million and a gain of $14.2 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 June 30, 2020, and 2019, our overall effective tax rates were impacted by the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, non-deductible and non-taxable items associated with our Ghanaian and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

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Six months ended June 30, 2020 compared to six months ended June 30, 2019




	Six Months Ended
	June 30,						Increase
	2020			2019			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	305,094		$	692,723		$	(387,629	)
Other income, net	1			1			—
Total revenues and other income	305,095			692,724			(387,629		)
Costs and expenses:
Oil and gas production	150,350			170,776			(20,426		)
Facilities insurance modifications, net	8,090			(17,743		)	25,833
Exploration expenses	60,316			60,249			67
General and administrative	39,097			63,980			(24,883		)
Depletion, depreciation and amortization	215,159			269,533			(54,374		)
Impairment of long-lived assets	150,820			—			150,820
Interest and other financing costs, net	56,109			94,844			(38,735		)
Derivatives, net	(35,963		)	62,900			(98,863		)
Other expenses, net	25,157			326			24,831
Total costs and expenses	669,135			704,865			(35,730		)
Income (loss) before income taxes	(364,040		)	(12,141		)	(351,899		)
Income tax expense (benefit)	18,118			23,928			(5,810		)
Net income (loss)	$	(382,158	)	$	(36,069	)	$	(346,089	)

Oil and gas revenue. Oil and gas revenue decreased by $387.6 million as a result of lower volumes sold due to cargo timing in our international operations and lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic. We sold 10,084 MBoe at an average realized price per barrel equivalent of $30.25 during the six months ended June 30, 2020 and 11,369 MBoe at an average realized price per barrel equivalent of $60.93 during the six months ended June 30, 2019.

Oil and gas production. Oil and gas production costs decreased by $20.4 million during the six months ended June 30, 2020, as compared to the six months ended June 30, 2019 as a result of lower sales volumes in the current versus prior period due to cargo timing in our international operations.

Facilities insurance modifications, net. During the six months ended June 30, 2020, we incurred $8.1 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue versus $22.2 million during the six months ended June 30, 2019. During the six months ended June 30, 2020 and 2019, these costs were offset by zero and $39.9 million, respectively, of hull and machinery insurance proceeds.

General and administrative. General and administrative costs decreased by $24.9 million during the six months ended June 30, 2020, as compared with the six months ended June 30, 2019 primarily as a result of headcount and other cost reductions.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $54.4 million during the six months ended June 30, 2020, as compared with the six months ended June 30, 2019 primarily as a result of increased reserves recorded in the fourth quarter of 2019, a lower cost basis in the U.S. Gulf of Mexico associated with an impairment recorded in the first quarter of 2020 and lower sales volumes during the current period.

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 six months ended June 30, 2020 for oil and gas proved properties in the U.S. Gulf of Mexico.

Interest and other financing costs, net. Interest and other financing costs, net decreased $38.7 million primarily a result of the $24.8 million loss on extinguishment of debt primarily associated with the refinancing of our senior notes recorded during

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the second quarter of 2019 and lower interest rates during the six months ended June 30, 2020, as compared to the six months ended June 30, 2019.

Derivatives, net. During the six months ended June 30, 2020 and 2019, we recorded a gain of $36.0 million and a loss of $62.9 million, respectively, on our outstanding hedge positions. The losses recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net increased $24.8 million primarily related to $13.3 million in restructuring charges for employee severance and related benefit costs and asset impairments of $4.5 million.

Income tax expense (benefit). For the six months ended June 30, 2020, our overall effective tax rate was impacted by increases to our valuation allowance associated with our U.S. deferred tax assets, resulting in $30.9 million net U.S. deferred tax expense and by a $4.9 million current tax benefit related to certain U.S. tax losses carried back to years with a higher income tax rate. Additionally, for the six months ended June 30, 2020, and 2019, our overall effective tax rates were impacted by the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, non-deductible and non-taxable items associated with our U.S., Ghanaian and Equatorial Guinean operations, and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such losses or expenses.

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. Also, BP has agreed to partially carry our exploration, appraisal and development program in Mauritania and Senegal up to a contractually agreed cap. Current commodity prices, combined with our hedging program, partner carries and our current liquidity position support our remaining capital program for 2020.

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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 six months ended June 30, 2020 and 2019:



	Six Months Ended
	June 30,
	2020			2019
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by (used in) operating activities	$	(62,836	)	$	222,390
Net proceeds from issuance of senior notes	—			641,875
Borrowings under long-term debt	150,000			175,000
Advances under production prepayment agreement	50,000			—
Proceeds on sale of assets	1,713			—
	138,877			1,039,265
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	135,242			153,268
Other property	1,536			5,230
Notes receivable from partners	42,362			5,983
Payments on long-term debt	—			300,000
Redemption of senior secured notes	—			535,338
Purchase of treasury stock	4,947			1,983
Dividends	19,181			36,289
Deferred financing costs	136			1,981
	203,404			1,040,072
Decrease in cash, cash equivalents and restricted cash	$	(64,527	)	$	(807	)

Net cash provided by (used in) operating activities. Net cash used in operating activities for the six months ended June 30, 2020 was $62.8 million compared with net cash provided by operating activities for the six months ended June 30, 2019 of $222.4 million. The decrease in cash provided by operating activities in the six months ended June 30, 2020 when compared to the same period in 2019 is primarily a result of lower volumes sold due to cargo timing in our international operations and lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic.

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The following table presents our net debt and liquidity as of June 30, 2020:



	June 30, 2020
	(In thousands)
Cash and cash equivalents	$	164,091
Restricted cash	728
Senior Notes at par	650,000
Borrowings under the Facility	1,450,000
Borrowings under the Corporate Revolver	100,000
Net debt	$	2,035,181
Production prepayment agreement	50,000
Net debt and production prepayment agreement	$	2,085,181

Availability under the Facility	$	50,000
Availability under the Corporate Revolver	$	300,000
Available borrowings plus cash and cash equivalents	$	514,091
Availability under the Production Prepayment Agreement(1)	100,000
Available borrowings plus cash and cash equivalents plus Production Prepayment Agreement	$	614,091

__________________________________


(1)	Represents commitments under the Production Prepayment Agreement to be advanced in September 2020, subject to Kosmos' election.

Capital Expenditures and Investments

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.

In response to current economic conditions including the volatility in oil price and the COVID-19 pandemic, we have reduced our base business 2020 capital program by approximately 40%. We have identified capital reductions from discretionary expenditures related to exploration activities in the U.S. Gulf of Mexico, our basin-opening exploration portfolio and other non-critical work that does not impact safety and asset integrity. We currently estimate that we will spend approximately $200 - $225 million of capital expenditures on our base business, net of carry amounts related to the Mauritania and Senegal transactions with BP, for the year ending December 31, 2020. Through June 30, 2020, we have spent approximately $151 million.

Significant Sources of Capital

Facility

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Corporate Revolver

As of June 30, 2020, there were $100.0 million in outstanding borrowings under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $300 million.

As 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. In addition, as part of the amendment to relax the debt cover ratio, we agreed to include the advanced amounts under the Production Prepayment Agreement as part of the debt cover ratio calculation. We were in compliance with the financial covenants as of the most recent assessment date. The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

Our revolving letter of credit facility agreement (“LC Facility”) expired in July 2019. In May 2020, the remaining five outstanding letters of credit under the LC Facility totaling $3.1 million were released and the LC Facility was subsequently terminated in June 2020.

In 2019, we issued two letters of credit totaling $20.4 million under a new letter of credit arrangement, which does not require cash collateral. This arrangement contains customary cross default provisions.

7.125% Senior Notes due 2026

The Senior Notes mature on April 4, 2026. Interest is payable in arrears on each April 4 and October 4, commencing on October 4, 2019. The 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 rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company'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 Senior Notes as of March 31, 2020. The Senior Notes contain customary cross default provisions.

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Production Prepayment Agreement

In June 2020, the Company received $50 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 Production Prepayment Agreement is for up to $200 million of crude oil sales, with an additional $100 million committed by Trafigura in addition to the $50 million received in June 2020. The Company will sell to Trafigura a specified volume of crude oil each month as defined in the Volume Model, which is expected to be finalized in the third quarter of 2020 in accordance with the terms of the Production Prepayment Agreement (estimated at approximately 2 million barrels) for no more than 60 months following the funding in June 2020, such final delivery date being the "Final Delivery Date," provided, however, if the market value of the crude oil volumes delivered prior to the Final Delivery Date is equal to $57.5 million, then the Company's obligation would be considered fully satisfied. Under the Production Prepayment Agreement, upon the satisfaction of certain conditions provided in the Production Prepayment Agreement, the Company may elect for Trafigura to prepay for two additional tranches of crude oil in the amount of $100 million on September 30, 2020 and $50 million on or before March 31, 2021. If the Company makes such election, the total volume of crude oil to be sold will be adjusted accordingly.

As a condition to Trafigura’s obligations, the Company will ‎grant a mortgage interest in certain specified production fields located in the U.S. Gulf of Mexico.


•	the guarantor liquidity ratio (as defined in the glossary), not less than 1.20x and


•	the GoM liquidity ratio (as defined in the glossary), not less than 1.50x

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2020:



	Payments Due By Year(5)
	Total		2020(6)		2021		2022		2023		2024		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,200,000	$	—	$	56,000	$	422,571	$	428,571	$	428,572	$	864,286
Production prepayment agreement(2)	57,500		$	2,741	$	18,729	$	32,397	$	3,633	—		—
Interest payments on long-term debt(3)	475,459		55,254		104,801		96,546		80,561		66,159		72,138
Operating leases(4)	34,278		2,061		4,174		4,237		4,301		3,464		16,041

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(1)

Includes the scheduled principal maturities for the $650.0 million aggregate principal amount of Senior Notes issued in April 2019, and borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of June 30, 2020, 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 estimated value of crude oil to be delivered based on quoted future market prices, including $7.5 million of financing costs to be paid under the Production Prepayment Agreement. Volumes delivered prior to July 2021 are associated with financing costs. Any increases or decreases in future market prices would impact the scheduled maturities during the next five years and thereafter.


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


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

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(5)

Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts. 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 16 — Additional Financial Information for additional information regarding these liabilities.


(6)	Represents the period from July 1, 2020 through December 31, 2020.

The following table presents maturities by expected maturity dates, the weighted average interest rates expected to be paid on the Facility, Corporate Revolver and Production Prepayment Agreement 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,																		June 30,
	2020(4)			2021			2022			2023			2024			Thereafter			2020
	(In thousands, except percentages)
Fixed rate debt:
Senior Secured Notes	$	—		$	—		$	—		$	—		$	—		$	650,000		$	(580,554	)
Fixed interest rate	7.13		%	7.13		%	7.13		%	7.13		%	7.13		%	7.13		%
Variable rate debt:
Facility(1)	$	—		$	56,000		$	322,571		$	428,571		$	428,572		$	214,286		$	(1,450,000	)
Corporate Revolver	—			—			100,000			—			—			—			(100,000		)
Weighted average interest rate(2)	3.73		%	3.48		%	3.74		%	3.94		%	4.56		%	4.98		%
Production Prepayment Agreement:
Production Prepayment Agreement(3)	$	—		$	15,729		$	30,799		$	3,472		$	—		$	—		$	(57,500	)
Weighted average interest rate(2)	5.18		%	5.12		%	5.12		%	5.15		%	—		%	—		%

__________________________________


(1)	The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of June 30, 2020. 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)	Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver.


(3)	Represents estimated value of crude oil to be delivered as principal repayment based on quoted future market prices. Any increases or decreases in future market prices would impact the scheduled maturities during the next five years and thereafter.


(4)	Represents the period July 1, 2020 through December 31, 2020.

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 June 30, 2020, 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.

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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. 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, 2019 and in the "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations" section in our quarterly report on Form 10-Q for the quarter ended March 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;


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


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


•	other competitive pressures;


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


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


•	cost of compliance with laws and regulations;


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


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


•	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;

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•	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 10 — Derivative Financial Instruments and Note 11 — Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.

The following table reconciles the changes that occurred in fair values of our open derivative contracts during the six months ended June 30, 2020:



	Derivative Contracts Assets (Liabilities)
	Commodities
	(In thousands)
Fair value of contracts outstanding as of December 31, 2019	$	(8,521	)
Changes in contract fair value	31,615
Contract maturities	(34,814		)
Fair value of contracts outstanding as of June 30, 2020	$	(11,720	)

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 half of 2020 ranged between $13.24 and $69.96 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first half of 2020.

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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.

Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of June 30, 2020. Volumes and weighted average prices are net of any offsetting derivatives entered into.



				Weighted Average Price per Bbl													Asset (Liability)
				Net Deferred													Fair Value at
				Premium													June 30,
Term	Type of Contract	Index	MBbl	Payable/(Receivable)			Swap		Sold Put		Floor		Ceiling		Purchased Call		2020(3)
																	(In thousands)
2020:
Jul — Dec	Swaps	Dated Brent	5,275	$	—		$	42.67	$	—	$	—	$	—	$	—	$	9,856
Jul — Dec	Swaps	Argus LLS	3,000	—			29.98		—		—		—		—		(32,420		)
Jul — Dec	Call spreads	NYMEX WTI	(1)	1.20			—		—		—		45.00		35.00		3,551
Jul — Dec	Swaps with sold puts	Dated Brent	333	—			35.00		25.00		—		—		—		(2,040		)
Jul — Dec	Three-way collars	Dated Brent	1,000	—			—		25.00		32.50		40.00		—		(3,251		)
Jul — Dec	Sold calls(2)	Dated Brent	4,750	(0.19		)	—		—		—		80.83		—		673
2021:
Jan — Dec	Swaps with sold puts	Dated Brent	5,000	$	—		$	54.70	$	43.50	$	—	$	—	—		$	21,981
Jan — Dec	Three-way collars	Dated Brent	1,000	1.00			—		30.00		40.00		55.40		—		(126		)
Jan — Dec	Sold calls(2)	Dated Brent	7,000	—			—		—		—		70.09		—		(5,044		)
2022:
Jan — Dec	Sold calls(2)	Dated Brent	1,581	—			—		—		—		60.00		—		(4,900		)

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(1)	Added call spreads on 1.0 million barrels to open upside for U.S. Gulf of Mexico production.


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


(3)	Fair values are based on the average forward oil prices on June 30, 2020.

At June 30, 2020, our open commodity derivative instruments were in a net liability position of $11.7 million. Future fluctuations in oil prices could have a material impact on the valuation of our derivative financial instruments. As of June 30, 2020, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $59.5 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $53.8 million.

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Interest Rate Sensitivity

At June 30, 2020, we had indebtedness outstanding under the Facility of $1.45 billion and the Corporate Revolver of $100.0 million, which bore interest at floating rates. The interest rate on this indebtedness as of June 30, 2020 was approximately 3.8% and 5.2% respectively. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $0.3 million in interest expense per year. The commitment fees on the undrawn availability under the Facility and the Corporate Revolver are not subject to changes in interest rates.

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 June 30, 2020, 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, 2019 and in the "Item 1A. Risk Factors" section of our quarterly report on form 10-Q for the quarter ended March 31, 2020.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

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Item 5. Other Information.

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

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	August 3, 2020	/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
10.1		Offer Letter, dated November 12, 2019, between Kosmos Energy, LLC and Neal D. Shah

10.2		Deed of Release related to the Multi-Currency Revolving Letter of Credit Facility Agreement, dated June 19, 2020, among Kosmos Energy Credit International, as the Original Borrower, Kosmos Energy Ltd., as the Original Guarantor, and Societe Generale, London Branch, as the Original Lender, Facility Agent, Security Agent and Account Bank.

10.3†		Prepayment Agreement dated June 26, 2020 between Kosmos Energy Gulf of Mexico Operations, LLC and Trafigura Trading LLC.

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

___________________________________

† Certain confidential portions of this Exhibit have been omitted pursuant to Item 601(b) of Regulation S-K because the identified confidential portions (i) are not material and (ii) would be competitively harmful if publicly disclosed.

Kosmos Energy - 10-Q quarterly report FY2020 Q2

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