Quarterly Report (10-q)

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kos:MauritaniaAndSenegalSegmentMember 2020-01-01 2020-06-30 0001509991 us-gaap:OperatingSegmentsMember kos:GhanaSegmentMember 2020-06-30 0001509991 us-gaap:OperatingSegmentsMember kos:GhanaSegmentMember 2020-01-01 2020-06-30 0001509991 us-gaap:MaterialReconcilingItemsMember 2020-06-30 0001509991 us-gaap:CorporateNonSegmentMember 2020-06-30 0001509991 us-gaap:OperatingSegmentsMember kos:MauritaniaAndSenegalSegmentMember 2020-06-30 0001509991 us-gaap:OperatingSegmentsMember kos:U.S.GulfOfMexicoSegmentMember 2020-06-30 utreg:MBbls kos:tranche kos:letter_of_credit iso4217:USD utreg:bbl xbrli:pure utreg:MMBbls iso4217:USD xbrli:shares kos:segment iso4217:USD utreg:bbl kos:project xbrli:shares kos:Agreement utreg:km utreg:sqkm kos:exploration_well

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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.

Table of Contents



"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.

Table of Contents

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.

Table of Contents

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		—

__________________________________


(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

__________________________________

(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

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