Kosmos Energy - 10-Q quarterly report FY2020 Q1

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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 March 31, 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 May 6, 2020
Common Shares, $0.01 par value		405,190,996

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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	30
Item 3. Quantitative and Qualitative Disclosures about Market Risk	41
Item 4. Controls and Procedures	43

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3. Defaults Upon Senior Securities	45
Item 4. Mine Safety Disclosures	45
Item 5. Other Information	45
Item 6. Exhibits	45
Signatures	46
Index to Exhibits	47

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

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“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.
"GJFFDP"		Greater Jubilee Full Field Development Plan.
"GNPC"		Ghana National Petroleum Corporation.
“Greater Tortue Ahmeyim”		Ahmeyim and Guembeul discoveries.

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"GTA UUOA"		Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
"Hess"		Hess Corporation.
"HLS"		Heavy Louisiana Sweet.
"H&M"		Hull and Machinery insurance.
"Jubilee UUOA"		Unitization and Unit Operating Agreement covering the Jubilee Unit.
"KBSL"		Kosmos BP Senegal Limited.
"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.
“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.

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“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.
“Trap”		A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
"Trident"		Trident Energy.
“Undeveloped acreage”		Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.
"WCTP"		West Cape Three Points.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)



	March 31, 2020			December 31, 2019
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	126,507		$	224,502
Restricted cash	3,708			4,302
Receivables:
Joint interest billings, net	116,610			81,424
Oil sales	30,926			64,142
Other	54,866			28,727
Inventories	140,068			114,412
Prepaid expenses and other	29,802			36,192
Derivatives	112,028			12,856
Total current assets	614,515			566,557
Property and equipment:
Oil and gas properties, net	3,428,555			3,624,751
Other property, net	14,382			17,581
Property and equipment, net	3,442,937			3,642,332
Other assets:
Restricted cash	542			542
Long-term receivables	68,472			43,430
Deferred financing costs, net of accumulated amortization of $15,335 and $14,681 at March 31, 2020 and December 31, 2019, respectively	5,667			6,321
Deferred tax assets	—			32,779
Derivatives	29,383			2,302
Other	22,446			22,969
Total assets	$	4,183,962		$	4,317,232
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	228,492		$	149,483
Accrued liabilities	267,758			380,704
Derivatives	19,587			8,914
Total current liabilities	515,837			539,101
Long-term liabilities:
Long-term debt, net	2,059,929			2,008,063
Derivatives	3,039			11,478
Asset retirement obligations	235,138			230,526
Deferred tax liabilities	692,618			653,221
Other long-term liabilities	32,253			33,141
Total long-term liabilities	3,022,977			2,936,429
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at March 31, 2020 and December 31, 2019	—			—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 449,368,992 and 445,779,367 issued at March 31, 2020 and December 31, 2019, respectively	4,494			4,458
Additional paid-in capital	2,283,398			2,297,221
Accumulated deficit	(1,405,737		)	(1,222,970		)
Treasury stock, at cost, 44,263,269 shares at March 31, 2020 and December 31, 2019, respectively	(237,007		)	(237,007		)
Total stockholders’ equity	645,148			841,702
Total liabilities and stockholders’ equity	$	4,183,962		$	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
	March 31,
	2020			2019
Revenues and other income:
Oil and gas revenue	$	177,780		$	296,790
Other income, net	1			—
Total revenues and other income	177,781			296,790
Costs and expenses:
Oil and gas production	61,603			79,799
Facilities insurance modifications, net	8,038			(20,021		)
Exploration expenses	44,605			30,344
General and administrative	20,911			35,908
Depletion, depreciation and amortization	93,302			118,095
Impairment of long-lived assets	150,820			—
Interest and other financing costs, net	27,835			35,041
Derivatives, net	(136,038		)	77,085
Other expenses, net	23,929			2,119
Total costs and expenses	295,005			358,370
Loss before income taxes	(117,224		)	(61,580		)
Income tax expense (benefit)	65,543			(8,674		)
Net loss	$	(182,767	)	$	(52,906	)

Net loss per share:
Basic	$	(0.45	)	$	(0.13	)
Diluted	$	(0.45	)	$	(0.13	)

Weighted average number of shares used to compute net loss per share:
Basic	404,759			401,164
Diluted	404,759			401,164

Dividends declared per common share	$	0.0452		$	0.0452

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

(Unaudited)



				Additional
	Common Shares			Paid-in			Accumulated			Treasury
	Shares	Amount		Capital			Deficit			Stock			Total
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

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

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Three Months Ended March 31,
	2020			2019
Operating activities
Net loss	$	(182,767	)	$	(52,906	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	95,585			120,482
Deferred income taxes	72,177			(39,833		)
Unsuccessful well costs and leasehold impairments	19,228			5,506
Impairment of long-lived assets	150,820			—
Change in fair value of derivatives	(136,322		)	73,807
Cash settlements on derivatives, net (including $12.0 million and $(7.3) million on commodity hedges during 2020 and 2019)	9,016			(3,576		)
Equity-based compensation	9,346			8,441
Other	3,974			4,981
Changes in assets and liabilities:
Increase in receivables	(26,932		)	(47,219		)
(Increase) decrease in inventories	(27,123		)	2,212
Decrease in prepaid expenses and other	6,344			12,597
Increase (decrease) in accounts payable	79,009			(59,331		)
Decrease in accrued liabilities	(89,318		)	(42,508		)
Net cash used in operating activities	(16,963		)	(17,347		)
Investing activities
Oil and gas assets	(83,716		)	(78,377		)
Other property	(1,537		)	(1,071		)
Proceeds on sale of assets	1,713			—
Notes receivable from partners	(23,983		)	—
Net cash used in investing activities	(107,523		)	(79,448		)
Financing activities
Borrowings under long-term debt	50,000			175,000
Payments on long-term debt	—			(100,000		)
Purchase of treasury stock / tax withholdings	(4,947		)	(1,980		)
Dividends	(19,156		)	(18,147		)
Deferred financing costs	—			(1,160		)
Net cash provided by financing activities	25,897			53,713
Net decrease in cash, cash equivalents and restricted cash	(98,589		)	(43,082		)
Cash, cash equivalents and restricted cash at beginning of period	229,346			185,616
Cash, cash equivalents and restricted cash at end of period	$	130,757		$	142,534

Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest	$	54,694		$	40,536
Income taxes	$	26,874		$	10,438

See accompanying notes.

KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

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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. Accounting policies of particular importance to the presentation of our financial position and results of operations and required the application of significant judgment or estimates by management during the first quarter of 2020 included:

Impairment of Long‑Lived Assets

We review our long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360 — Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. Assets to be disposed of and assets not expected to provide any future service potential to us are recorded at the lower of carrying amount or fair value. Oil and gas properties are grouped in accordance with ASC 932 — Extractive Activities-Oil and Gas. The basis for grouping is a reasonable aggregation of properties typically by field or by logical grouping of assets with significant shared infrastructure.

For long-lived assets whereby the carrying value exceeds the estimated future undiscounted cash flows, the carrying amount is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 — Fair Value Measurement. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted-average cost of capital. Although we base the fair value estimate of each asset group on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserve quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.

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We believe the assumptions used in our analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows and fair value. Kosmos has consistently used an average of third-party industry forecasts to determine our pricing assumptions. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation.

Reclassifications

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

Cash, Cash Equivalents and Restricted Cash



	March 31, 2020		December 31, 2019
	(In thousands)
Cash and cash equivalents	$	126,507	$	224,502
Restricted cash - current	3,708		4,302
Restricted cash - long-term	542		542
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	130,757	$	229,346

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 $113.5 million and $112.3 million of materials and supplies and $26.6 million and $2.1 million of hydrocarbons as of March 31, 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.

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Oil and gas revenue is composed of the following:



	Three Months Ended March 31,
	2020		2019
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	24,370	$	89,115
Revenues from contract with customer - Ghana	49,672		119,330
Revenues from contract with customers - U.S. Gulf of Mexico	103,453		85,067
Provisional oil sales contracts	285		3,278
Oil and gas revenue	$	177,780	$	296,790

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 months ended March 31, 2020, we recognized $13.9 million 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 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 March 31, 2020 and 2019, revenue from Phillips 66 Company made up approximately 47% and 22%, respectively, and revenue from Shell Trading (US) Company made up approximately 20% and 5%, 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 is 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.

2019 Transactions

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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.

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 face of 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 March 31, 2020 and December 31, 2019, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $11.6 million and $14.0 million, respectively, and the long-term portions were $16.6 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 March 31, 2020 and December 31, 2019, the balance due from the national oil companies was $51.9 million and $27.4 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets.

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5. Property and Equipment

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



	March 31, 2020			December 31, 2019
	(In thousands)
Oil and gas properties:
Proved properties	$	5,082,805		$	4,904,648
Unproved properties	526,907			814,065
Total oil and gas properties	5,609,712			5,718,713
Accumulated depletion	(2,181,157		)	(2,093,962		)
Oil and gas properties, net	3,428,555			3,624,751

Other property	59,749			61,598
Accumulated depreciation	(45,367		)	(44,017		)
Other property, net	14,382			17,581

Property and equipment, net	$	3,442,937		$	3,642,332

We recorded depletion expense of $87.2 million and $111.0 million for the three months ended March 31, 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. During the three months ended March 31, 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.

6. Suspended Well Costs

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the three months ended March 31, 2020. The table excludes $9.7 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.



	March 31, 2020
	(In thousands)
Beginning balance	$	445,790
Additions to capitalized exploratory well costs pending the determination of proved reserves	663
Reclassification due to determination of proved reserves	(265,740		)
Capitalized exploratory well costs charged to expense	—
Ending balance	$	180,713

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



	March 31, 2020		December 31, 2019
	(In thousands, except well counts)
Exploratory well costs capitalized for a period of one year or less	$	29,061	$	29,121
Exploratory well costs capitalized for a period of one to two years	36,526		78,245
Exploratory well costs capitalized for a period of three years or greater	115,126		338,424
Ending balance	$	180,713	$	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 March 31, 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.

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 months ended March 31, 2020 and 2019 are as follows:



	Three Months Ended March 31,
	2020		2019
	(In thousands)
Operating lease cost	$	1,258	$	1,407
Short-term lease cost(1)	10,368		5
Total lease cost	$	11,626	$	1,412

__________________________________


(1)	Includes $9.9 million of costs associated with short-term drilling contracts.

Other information related to operating leases at March 31, 2020 and 2019, is as follows:

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	March 31, 2020			December 31, 2019
(In thousands, except lease term and discount rate)
Balance sheet classifications
Other assets (right-of-use assets)	$	19,563		$	20,008
Accrued liabilities (current maturities of leases)	1,942			1,139
Other long-term liabilities (non-current maturities of leases)	21,485			22,240

Weighted average remaining lease term	8.6 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 three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(In thousands)
Operating cash flows for operating leases	$	337	$	1,223
Investing cash flows for operating leases(1)	$	9,867	$	—


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

Future minimum rental commitments under our leases at March 31, 2020, are as follows:



	Operating Leases(1)
	(In thousands)
2020(2)	$	2,979
2021	4,172
2022	4,235
2023	4,299
2024	3,462
Thereafter	16,036
Total undiscounted lease payments	$	35,183
Less: Imputed interest	(11,756		)
Total lease liabilities	$	23,427

__________________________________


(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 April 1, 2020 through December 31, 2020.

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8. Debt



	March 31, 2020			December 31, 2019
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,400,000		$	1,400,000
Corporate Revolver	50,000			—
Senior Notes	650,000			650,000
Total	2,100,000			2,050,000
Unamortized deferred financing costs and discounts(1)	(40,071		)	(41,937		)
Long-term debt, net	$	2,059,929		$	2,008,063

__________________________________


(1)	Includes $31.2 million and $32.8 million of unamortized deferred financing costs related to the Facility as of March 31, 2020 and December 31, 2019, respectively; $7.3 million and $9.1 million of unamortized deferred financing costs and discounts related to the Senior Notes as of March 31, 2020 and December 31, 2019, respectively.

Facility

In February 2018, the Company amended and restated the Facility with a total commitment of $1.5 billion from a number of financial institutions, with additional commitments up to $0.5 billion being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. As part of the Facility amendment and restatement process in 2018, the lenders approved a redetermination, setting the total commitments under our Facility at $1.5 billion (effective February 22, 2018) which was increased to $1.7 billion (effective January 31, 2019) after the election to exercise $0.2 billion of additional commitments in the fourth quarter of 2018. The commitments were reduced by $0.1 billion to $1.6 billion following the Senior Notes issuance in April 2019. As of March 31, 2020, borrowings under the Facility totaled $1.4 billion and the undrawn availability under the facility was $0.2 billion. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. In April 2020, following the lender's annual redetermination, the available borrowing base and Facility size were both reduced from $1.6 billion to $1.5 billion. As a result, the undrawn availability under the Facility is $0.1 billion in April 2020. 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 March 31, 2020, we have $31.2 million of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility.

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 March 31, 2020, we had no letters of credit issued under the Facility.

We were in compliance with the financial covenants contained in the Facility as of March 31, 2020 (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 March 31, 2020, the undrawn availability under the Corporate Revolver was $350.0 million. As of March 31, 2020, we have $5.7 million of net deferred financing costs related to the Corporate Revolver, which will be amortized over its remaining term. We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2020 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

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Revolving Letter of Credit Facility

Our revolving letter of credit facility agreement (“LC Facility”) expired in July 2019, however, as of March 31, 2020, there were five outstanding letters of credit totaling $3.1 million under the LC Facility, which will remain outstanding until the respective letters of credit expire.

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.

At March 31, 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(3)		2022		2023		2024		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,100,000	$	—	$	174,800	$	334,200	$	271,600	$	440,829	$	878,571

__________________________________

(1)

Includes the scheduled principal maturities for the $650.0 million aggregate principal amount of Senior Notes issued in April 2019, borrowings under the Facility and Corporate Revolver. The scheduled maturities of debt related to the Facility as of March 31, 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 April 1, 2020 through December 31, 2020.


(3)	Approximately $169.0 million of the 2021 principal repayments will now be due in 2022 as a result of the Facility's lender redetermination in April 2020.

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Interest and other financing costs, net

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



	Three Months Ended March 31,
	2020			2019
	(In thousands)
Interest expense	$	31,766		$	38,172
Amortization—deferred financing costs	2,283			2,387
Capitalized interest	(6,527		)	(7,251		)
Deferred interest	314			836
Interest income	(1,079		)	(652		)
Other, net	1,078			1,549
Interest and other financing costs, net	$	27,835		$	35,041

9. 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.

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 March 31, 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
2020:
Apr — Dec	Three-way collars	Dated Brent	4,500	$	0.25	$	—	$	50.00	$	57.50	$	80.18
Apr — Dec	Swaps with sold puts	Dated Brent	3,500	—		45.94		35.18		—		—
Apr — Dec	Put spread	Dated Brent	4,500	0.75		—		50.00		59.17		—
Apr — Dec	Sold calls(1)	Dated Brent	6,000	—		—		—		—		85.00
2021:
Jan — Dec	Swaps with sold puts	Dated Brent	6,000	$	—	$	53.52	$	41.77	$	—	$	—
Jan — Dec	Sold calls(1)	Dated Brent	6,000	—		—		—		—		71.67

__________________________________


(1)	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. We retained 2.0 MMBbls of our April 2020 through December 2020 Dated Brent swap contracts with a fixed price of $35.00 per barrel and a sold put at $25.00 per barrel. In addition, we entered into Argus LLS swap contracts for 4.0 MMBbls from May 2020 through December 2020 with an average fixed price of $29.98 per barrel.

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The following tables disclose the Company’s derivative instruments as of March 31, 2020 and December 31, 2019, and gain/(loss) from derivatives during the three months ended March 31, 2020 and 2019, respectively:



		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	March 31, 2020			December 31, 2019
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity	Derivatives assets—current	$	112,028		$	12,856
Provisional oil sales	Receivables: Oil Sales	—			(3,287		)
Commodity	Derivatives assets—long-term	29,383			2,302
Derivative liabilities:
Commodity	Derivatives liabilities—current	(19,587		)	(8,914		)
Commodity	Derivatives liabilities—long-term	(3,039		)	(11,478		)
Total derivatives not designated as hedging instruments		$	118,785		$	(8,521	)



		Amount of Gain/(Loss)
		Three Months Ended
		March 31,
Type of Contract	Location of Gain/(Loss)	2020		2019
		(In thousands)
Derivatives not designated as hedging instruments:
Commodity(1)	Oil and gas revenue	$	284	$	3,278
Commodity	Derivatives, net	136,038		(77,085		)
Total derivatives not designated as hedging instruments		$	136,322	$	(73,807	)

__________________________________


(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 March 31, 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.

10. Fair Value Measurements

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


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


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

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

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 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)
March 31, 2020
Assets:
Commodity derivatives	$	—	$	141,411		$	—	$	141,411
Provisional oil sales	—		—			—		—
Liabilities:
Commodity derivatives	—		(22,626		)	—		(22,626		)
Total	$	—	$	118,785		$	—	$	118,785
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 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 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.

Provisional Oil Sales

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

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Debt

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



	March 31, 2020				December 31, 2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
Senior Notes	$	642,787	$	365,619	$	642,550	$	664,957
Corporate Revolver	50,000		50,000		—		—
Facility	1,400,000		1,400,000		1,400,000		1,400,000
Total	$	2,092,787	$	1,815,619	$	2,042,550	$	2,064,957

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

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 at March 31, 2020. 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 utilized 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 analyzed sensitivities to prices, production, and risk adjustment factors.

At March 31, 2020, 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.

During the three months ended March 31, 2020, oil prices declined significantly as compared to December 31, 2019, resulting in a significant decrease in value of the Company's proved oil and gas reserves. As such, the carrying amount of certain of the Company's proved oil and gas properties in the U.S. Gulf of Mexico exceeded the expected undiscounted future net cash flows resulting 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. These impairment charges are included in Impairments of long-lived assets on the consolidated statement of operations for the three months ended March 31, 2020. The Company did not recognize an impairment of proved oil and gas properties during the three months ended March 31, 2019. 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.

11. 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 $9.3 million and $8.4 million during the three months ended March 31, 2020 and 2019, respectively. The total tax benefit was $2.1 million and $1.3 million during the three months ended March 31, 2020 and 2019, respectively. Additionally, we recorded a net tax shortfall (windfall)

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related to equity-based compensation of $0.9 million and $1.2 million during the three months ended March 31, 2020 and 2019, respectively. The fair value of awards vested was $25.5 million and $13.2 million during the three months ended March 31, 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 March 31, 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)	2,780		6.46		3,209		8.88
Forfeited(1)	(765	)	6.32		(389	)	8.01
Vested	(1,871	)	5.84		(2,572	)	9.47
Outstanding at March 31, 2020	4,875		5.99		8,046		8.27

__________________________________


(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 March 31, 2020, total equity-based compensation to be recognized on unvested restricted stock units is $50.8 million over a weighted average period of 2.19 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 March 31, 2020, the Company had approximately 6.6 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 $4.83 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.

12. 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 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.

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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-months ended March 31, 2020, we increased our valuation allowance associated with our U.S. deferred tax assets to $76.4 million 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.

On March 27, 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 March 31,
	2020			2019
	(In thousands)
United States	$	(190,137	)	$	(55,741	)
Foreign—other	72,913			(5,839		)
Income (loss) before income taxes	$	(117,224	)	$	(61,580	)

For the three months ended, March 31, 2020, and 2019, our effective tax rate was 56% and 14%, respectively.

For the three months ended March 31, 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 months ended March 31, 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 2018, in Ghana to federal income tax return years 2014 through 2018.

As of March 31, 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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13. Net Loss Per Share

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



	Three Months Ended
	March 31,
	2020			2019
	(In thousands, except per share data)
Numerator:
Net loss allocable to common stockholders	$	(182,767	)	$	(52,906	)
Denominator:
Weighted average number of shares outstanding:
Basic	404,759			401,164
Restricted stock awards and units(1)(2)	—			—
Diluted	404,759			401,164
Net loss per share:
Basic	$	(0.45	)	$	(0.13	)
Diluted	$	(0.45	)	$	(0.13	)

__________________________________


(1)	We excluded outstanding restricted stock awards and units of 11.0 million and 8.9 million for the three months ended March 31, 2020 and 2019, respectively, from the computations of diluted net loss per share because the effect would have been anti-dilutive.

14. 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 March 31, 2020 and December 31, 2019, the Company had performance bonds totaling $222.0 million for our supplemental bonding requirements stipulated by the BOEM and $3.7 million to another operator 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 March 31, 2020 and December 31, 2019, we had zero cash collateral against these secured performance bonds.

Dividends

On February 24, 2020, we announced our quarterly cash dividend of $0.0452 per common share. The dividend was paid on March 26, 2020 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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15. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:



	March 31, 2020		December 31, 2019
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	125,583	$	152,490
Revenue payable	25,259		32,482
Current asset retirement obligations	3,029		4,527
General and administrative expenses	4,265		44,575
Interest	4,376		33,584
Income taxes	82,883		103,566
Taxes other than income	3,130		3,375
Derivatives	—		4,837
Other	19,233		1,268
	$	267,758	$	380,704

Asset Retirement Obligations

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



	March 31, 2020
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	235,053
Liabilities incurred during period	—
Liabilities settled during period	(3,688		)
Revisions in estimated retirement obligations	2,150
Accretion expense	4,652
Ending asset retirement obligations	$	238,167

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 March 31, 2020 and 2019, we incurred approximately $8.0 million and $11.0 million, respectively in expenditures offset by approximately zero and $31.0 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 March 31,
	2020		2019
	(In thousands)
Loss on disposal of inventory	$	1,467	$	187
Loss on ARO liability settlements	2,150		1,918
Restructuring charges	13,915		—
Other, net	6,397		14
Other expenses, net	$	23,929	$	2,119

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

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16. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration and development of oil and gas. At March 31, 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 March 31, 2020
Revenues and other income:
Oil and gas revenue	$	49,708		$	24,619		$	—		$	103,453		$	—		$	—		$	177,780
Other income, net	1			—			—			447			(112,009		)	111,562			1
Total revenues and other income	49,709			24,619			—			103,900			(112,009		)	111,562			177,781
Costs and expenses:
Oil and gas production	18,042			11,475			—			32,086			—			—			61,603
Facilities insurance modifications, net	8,038			—			—			—			—			—			8,038
Exploration expenses	85			2,719			3,474			13,967			24,360			—			44,605
General and administrative	3,890			1,738			2,109			4,004			31,862			(22,692		)	20,911
Depletion, depreciation and amortization	19,731			8,894			15			63,834			828			—			93,302
Impairment of long-lived assets	—			—			—			150,820			—			—			150,820
Interest and other financing costs, net(1)	14,831			(369		)	(6,626		)	4,689			17,094			(1,784		)	27,835
Derivatives, net	—			—			—			—			(136,038		)	—			(136,038		)
Other expenses, net	(116,372		)	(15,756		)	2,793			3,652			13,574			136,038			23,929
Total costs and expenses	(51,755		)	8,701			1,765			273,052			(48,320		)	111,562			295,005
Income (loss) before income taxes	101,464			15,918			(1,765		)	(169,152		)	(63,689		)	—			(117,224		)
Income tax expense (benefit)	38,221			4,588			—			30,903			(8,169		)	—			65,543
Net income (loss)	$	63,243		$	11,330		$	(1,765	)	$	(200,055	)	$	(55,520	)	$	—		$	(182,767	)

Consolidated capital expenditures	$	16,486		$	6,770		$	3,121		$	38,654		$	19,434		$	—		$	84,465

As of March 31, 2020
Property and equipment, net	$	1,484,630		$	462,472		$	444,561		$	1,024,179		$	27,095		$	—		$	3,442,937
Total assets	$	1,724,154		$	626,511		$	611,081		$	3,078,851		$	12,235,030		$	(14,091,665	)	$	4,183,962

______________________________________


(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 March 31, 2019
Revenues and other income:
Oil and gas revenue	$	122,919		$	88,805	$	—		$	85,066		$	—		$	—		$	296,790
Other income, net	—			—		—			135			72,809			(72,944		)	—
Total revenues and other income	122,919			88,805		—			85,201			72,809			(72,944		)	296,790
Costs and expenses:
Oil and gas production	30,057			22,605		—			27,137			—			—			79,799
Facilities insurance modifications, net	(20,021		)	—		—			—			—			—			(20,021		)
Exploration expenses	52			3,171		6,442			11,194			9,485			—			30,344
General and administrative	5,956			2,045		2,287			7,393			44,205			(25,978		)	35,908
Depletion, depreciation and amortization	54,863			23,017		15			39,090			1,110			—			118,095
Interest and other financing costs, net(1)	20,653			—		(6,793		)	5,929			17,036			(1,784		)	35,041
Derivatives, net	—			—		—			31,903			45,182			—			77,085
Other expenses, net	45,100			340		229			1,592			40			(45,182		)	2,119
Total costs and expenses	136,660			51,178		2,180			124,238			117,058			(72,944		)	358,370
Income (loss) before income taxes	(13,741		)	37,627		(2,180		)	(39,037		)	(44,249		)	—			(61,580		)
Income tax expense (benefit)	(4,983		)	15,531		—			(8,206		)	(11,016		)	—			(8,674		)
Net income (loss)	$	(8,758	)	$	22,096	$	(2,180	)	$	(30,831	)	$	(33,233	)	$	—		$	(52,906	)

Consolidated capital expenditures	$	34,967		$	14,936	$	2,252		$	45,882		$	12,191		$	—		$	110,228

As of March 31, 2019
Property and equipment, net	$	1,681,317		$	470,974	$	414,035		$	1,309,412		$	39,065		$	—		$	3,914,803
Total assets	$	1,938,645		$	533,244	$	528,068		$	3,369,271		$	10,092,342		$	(11,959,714	)	$	4,501,856

______________________________________


(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.



	Three Months Ended March 31,
	2020			2019
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	83,716		$	78,377
Other property	1,537			1,071
Adjustments:
Changes in capital accruals	(23,310		)	14,925
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	25,377			24,838
Capitalized interest	(6,527		)	(7,251		)
Other	3,672			(1,732		)
Total consolidated capital expenditures	$	84,465		$	110,228

______________________________________


(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. The Jubilee Operator is currently working with the contractor to determine when the contractor will return to Ghana 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 over 30% 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 ongoing 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.

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•	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.


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


•	Reduced Company headcount resulting in restructuring charges for employee severance and related benefits totaling approximately $13.9 million during the three months ended March 31, 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.

Recent Developments

Ghana

Jubilee

During the first quarter of 2020, Jubilee production averaged approximately 79,200 Bopd (gross). The planned work to enhance gas handling capacity was successfully performed by the operator during the first quarter of 2020, with subsequent production rates of around 90,000 Bopd being achieved.

TEN

During the first quarter of 2020, TEN production averaged approximately 51,700 Bopd (gross). In January 2020, the Operator began drilling development well NT-09. Kosmos expects the oil-production well to be brought online in the second quarter of 2020.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 28,300 Boepd (net) for the first quarter of 2020.

In January 2020, we completed drilling the Oldfield exploration well. The well did not encounter commercial quantities of hydrocarbon and was plugged and abandoned.

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.

As a result of current market conditions, the operator of the Delta House platform in the U.S. Gulf of Mexico has chosen to shut-in the facility during the month of May 2020 and accelerate planned maintenance. While the majority of our fields have a positive operating margin at $10 HLS, the shut-in of Delta House will impact second quarter production by approximately 5,500 Boepd (net) from fields processed through the facility. In addition, we will temporarily shut-in approximately 1,500 Boepd (net) at other facilities during the second quarter, resulting in approximately 7,000 Boepd of net Kosmos production shut-in during the second quarter. We currently expect the shut-ins to last through the end of May 2020, however timing will depend on future market conditions. The shut-in of fields in the U.S. Gulf of Mexico occurs on a seasonal basis as a result of hurricanes, and, based on this experience, we do not expect any damage to the reservoirs.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 36,200 Bopd (gross) in the first 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.

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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 months ended March 31, 2020 and 2019 are included in the following tables:



	Three Months Ended March 31,
	2020		2019
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	3,450		4,690
Gas (MMcf)	1,982		1,801
NGL (MBbl)	193		113
Total (MBoe)	3,973		5,103
Total (Boepd)	43,659		56,077

Revenues:
Oil sales	$	171,916	$	290,864
Gas sales	3,719		3,662
NGL sales	2,145		2,264
Total revenues	$	177,780	$	296,790

Average oil sales price per Bbl	$	49.83	$	62.02
Average gas sales price per Mcf	1.88		2.03
Average NGL sales price per Bbl	11.11		20.13
Average total sales price per Boe	44.74		58.16

Costs:
Oil and gas production, excluding workovers	$	57,417	$	72,715
Oil and gas production, workovers	4,186		7,084
Total oil and gas production costs	$	61,603	$	79,799

Depletion, depreciation and amortization	$	93,302	$	118,095

Average cost per Boe:
Oil and gas production, excluding workovers	$	14.45	$	14.25
Oil and gas production, workovers	1.05		1.39
Total oil and gas production costs	15.50		15.64

Depletion, depreciation and amortization	23.48		23.14
Total	$	38.98	$	38.78

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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 March 31, 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
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	0.46	9	2.66	17	3.63

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 March 31, 2020 compared to three months ended March 31, 2019



	Three Months Ended
	March 31,						Increase
	2020			2019			(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	177,780		$	296,790		$	(119,010	)
Other income, net	1			—			1
Total revenues and other income	177,781			296,790			(119,009		)
Costs and expenses:
Oil and gas production	61,603			79,799			(18,196		)
Facilities insurance modifications, net	8,038			(20,021		)	28,059
Exploration expenses	44,605			30,344			14,261
General and administrative	20,911			35,908			(14,997		)
Depletion, depreciation and amortization	93,302			118,095			(24,793		)
Impairment of long-lived assets	150,820			—			150,820
Interest and other financing costs, net	27,835			35,041			(7,206		)
Derivatives, net	(136,038		)	77,085			(213,123		)
Other expenses, net	23,929			2,119			21,810
Total costs and expenses	295,005			358,370			(63,365		)
Loss before income taxes	(117,224		)	(61,580		)	(55,644		)
Income tax expense (benefit)	65,543			(8,674		)	74,217
Net loss	$	(182,767	)	$	(52,906	)	$	(129,861	)

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Oil and gas revenue. Oil and gas revenue decreased by $119.0 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 exacerbated by the COVID-19 pandemic. We sold 3,973 MBoe at an average realized price per barrel equivalent of $44.74 during the three months ended March 31, 2020 and 5,103 MBoe at an average realized price per barrel equivalent of $58.16 during the three months ended March 31, 2019.

Oil and gas production. Oil and gas production costs decreased by $18.2 million during the three months ended March 31, 2020, as compared to the three months ended March 31, 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 three months ended March 31, 2020, we incurred $8.0 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue versus $11.0 million during the three months ended March 31, 2019. During the three months ended March 31, 2020 and 2019, these costs were offset by zero and $31.0 million, respectively, of hull and machinery insurance proceeds.

Exploration expenses. Exploration expenses increased by $14.3 million during the three months ended March 31, 2020, as compared to the three months ended March 31, 2019. The increase is primarily a result of unsuccessful well costs recorded in 2020 for the Oldfield exploration well in the U.S. Gulf of Mexico versus none reported in the prior period.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $24.8 million during the three months ended March 31, 2020, as compared with the three months ended March 31, 2019 as a result of depletion recognized in relation to lower sales of oil and gas in the current period.

Interest and other financing costs, net. Interest and other financing costs, net decreased $7.2 million primarily a result of a decreased outstanding debt balance and lower interest rates during the three months ended March 31, 2020, as compared to the three months ended March 31, 2019.

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 three months ended March 31, 2020 for oil and gas proved properties in the U.S. Gulf of Mexico.

Derivatives, net. During the three months ended March 31, 2020 and 2019, we recorded a gain of $136.0 million and a loss of $77.1 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.

Other expenses, net. Other expenses, net increased $21.8 million primarily related to $13.9 million in restructuring charges for employee severance and related benefit costs and asset impairments of $4.1 million.

Income tax expense (benefit). For the three months ended March 31, 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 three months ended March 31, 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.

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

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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.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the three months ended March 31, 2020 and 2019:



	Three Months Ended
	March 31,
	2020			2019
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash used in operating activities	$	(16,963	)	$	(17,347	)
Borrowings under long-term debt	50,000			175,000
Proceeds on sale of assets	1,713			—
	34,750			157,653
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	83,716			78,377
Other property	1,537			1,071
Notes receivable from partners	23,983			—
Payments on long-term debt	—			100,000
Purchase of treasury stock	4,947			1,980
Dividends	19,156			18,147
Deferred financing costs	—			1,160
	133,339			200,735
Decrease in cash, cash equivalents and restricted cash	$	(98,589	)	$	(43,082	)

Net cash used in operating activities. Net cash used in operating activities for the three months ended March 31, 2020 was $17.0 million compared with net cash used in operating activities for the three months ended March 31, 2019 of $17.3 million.

The following table presents our net debt and liquidity as of March 31, 2020:



	March 31, 2020
	(In thousands)
Cash and cash equivalents	$	126,507
Restricted cash	4,250
Senior Notes at par	650,000
Borrowings under the Facility	1,400,000
Borrowings under the Corporate Revolver	50,000
Net debt	$	1,969,243

Availability under the Facility(1)	$	200,000
Availability under the Corporate Revolver	$	350,000
Available borrowings plus cash and cash equivalents	$	676,507

__________________________________


(1)	In April 2020, following the lender's annual redetermination, the available borrowing base and Facility size were both reduced from $1.6 billion to $1.5 billion. As a result, the undrawn availability under the Facility is $100.0 million in April 2020.

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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 March 31, 2020, we have spent approximately $84 million.

Significant Sources of Capital

Facility

We were in compliance with the financial covenants contained in the Facility as of March 31, 2020 (the most recent assessment date). The Facility contains customary cross default provisions.

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Corporate Revolver

As of March 31, 2020, there were $50 million in outstanding borrowings under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $350 million. We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2020 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

Revolving Letter of Credit Facility

We had a revolving letter of credit facility agreement (“LC Facility”), which matured in July 2019. As of March 31, 2020, there were five outstanding letters of credit totaling $3.1 million under the LC Facility.

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.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of March 31, 2020:



	Payments Due By Year(4)
	Total		2020(5)		2021(6)		2022		2023		2024		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,100,000	$	—	$	174,800	$	334,200	$	271,600	$	440,829	$	878,571
Interest payments on long-term debt(2)	482,560		70,146		101,483		93,031		79,122		66,401		72,377
Operating leases(3)	35,183		2,979		4,172		4,235		4,299		3,462		16,036

__________________________________

(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 March 31, 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)	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.

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

(4)

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 15 — Additional Financial Information for additional information regarding these liabilities.


(5)	Represents the period from April 1, 2020 through December 31, 2020.


(6)	Approximately $169.0 million of the 2021 principal repayments will now be due in 2022 as a result of the Facility's lender redetermination in April 2020.

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



																			Asset
																			(Liability)
																			Fair Value at
	Years Ending December 31,																		March 31,
	2020(3)			2021			2022			2023			2024			Thereafter			2020
	(In thousands, except percentages)
Fixed rate debt:
Senior Secured Notes	$	—		$	—		$	—		$	—		$	—		$	650,000		$	(365,619	)
Fixed interest rate	7.13		%	7.13		%	7.13		%	7.13		%	7.13		%	7.13		%
Variable rate debt:
Facility(1)	$	—		$	174,800		$	284,200		$	271,600		$	440,829		$	228,571		$	(1,400,000	)
Corporate Revolver	—			—			50,000			—			—			—			(50,000		)
Weighted average interest rate(2)	3.77		%	3.56		%	3.98		%	4.21		%	4.74		%	5.09		%

__________________________________


(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 March 31, 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 the period April 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 March 31, 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. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management during the first quarter of 2020. Other than items discussed in Note 2 — Accounting Policies, there have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended December 31, 2019.

Impairment of Long‑Lived Assets

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;

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•	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;


•	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 this quarterly report on Form 10-Q and our annual report on Form 10-K.

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

Item 3. Qualitative and Quantitative Disclosures About Market Risk

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

We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial

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Statements and Supplementary Data — Note 2 — Accounting Policies, Note 9 — Derivative Financial Instruments and Note 10 — Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.

The following table reconciles the changes that occurred in fair values of our open derivative contracts during the three months ended March 31, 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	136,322
Contract maturities	(9,016		)
Fair value of contracts outstanding as of March 31, 2020	$	118,785

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 quarter of 2020 ranged between $66.09 and $17.68 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first quarter of 2020.

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 March 31, 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										March 31,
Term	Type of Contract	Index	MBbl	Payable/(Receivable)		Swap		Sold Put		Floor		Ceiling		2020(2)
														(In thousands)
2020:
Apr — Dec	Three-way collars	Dated Brent	4,500	$	0.25	$	—	$	50.00	$	57.50	$	80.18	$	30,661
Apr — Dec	Swaps with sold puts	Dated Brent	3,500	—		45.94		35.18		—		—		19,647
Apr — Dec	Put spread	Dated Brent	4,500	0.75		—		50.00		59.17		—		36,067
Apr — Dec	Sold calls(1)	Dated Brent	6,000	—		—		—		—		85.00		(273		)
2021:
Jan — Dec	Swaps with sold puts	Dated Brent	6,000	$	—	$	53.52	$	41.77	$	—	$	—	$	34,968
Jan — Dec	Sold calls(1)	Dated Brent	6,000	—		—		—		—		71.67		(2,285		)

__________________________________


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


(2)	Fair values are based on the average forward oil prices on March 31, 2020.

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At March 31, 2020, our open commodity derivative instruments were in a net asset position of $118.8 million. Future fluctuations in oil prices could have a material impact on the valuation of our derivative financial instruments. As of March 31, 2020, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $28.0 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $15.6 million.

Interest Rate Sensitivity

At March 31, 2020, we had indebtedness outstanding under the Facility of $1.4 billion and the Corporate Revolver of $50.0 million, which bore interest at floating rates. The interest rate on this indebtedness as of March 31, 2020 was approximately 4.0% and 5.9% respectively. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $1.4 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 March 31, 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, other than the following:

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The COVID-19 pandemic and outbreaks of other diseases may adversely affect our business operations and financial condition.

The global spread of the COVID-19 pandemic, and the travel restrictions, “shelter-in-place” measures and other governmental actions taken to inhibit its spread, has created significant volatility, uncertainty and economic disruption in the markets in which we operate, which has affected our business and operations and those of our suppliers, contractors and partners. Certain contracts necessary for our ongoing exploration, development and production operations have been suspended or terminated as a consequence of the pandemic, and the pandemic has constrained our ability and the ability of our suppliers, contractors and partners to develop and implement effective plans to explore for oil and gas and to develop or produce certain of our license areas. The measures taken to combat the pandemic have limited access to qualified personnel, increased costs associated with ensuring the safety and health of our personnel, restricted the transportation of personnel, equipment and supplies to and from our areas of operation, and they have diverted the time, attention and resources of government agencies that are necessary to conduct our operations.

Access to our FPSOs and other production facilities could also be restricted and/or suspended as result of COVID-19. Our FPSOs and production facilities are able to operate for short periods of time without access to the mainland, but if travel restrictions continue, we and the operators of the impacted fields could be required to cease production and other operations until such restrictions were lifted. Any losses we experience as a result of COVID-19 that impact sales or delay production may not be covered by our insurance policies.

The extent to which our results are affected by COVID-19 will largely depend on future developments that cannot be accurately predicted. While the full impact of this outbreak is not yet known, we are closely monitoring the spread of COVID-19 and continually assessing its potential effects on our liquidity, capital resources, operations and business and those of the third parties we rely on. In addition, the adverse effect of the COVID-19 pandemic on our business, results of operations, financial condition and cash flows may heighten many of the other risks described in the "Risk Factors" section of this report and our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Significant outbreaks of other contagious diseases or adverse public health developments could also have a material impact on our business operations and financial condition. Many of our operations are currently in developing countries that are susceptible to outbreaks of disease, such as the Ebola epidemic in 2014 and 2015 in West Africa and may lack the resources to effectively contain such an outbreak quickly.

Our ability to utilize net operating loss carryforwards may be subject to certain limitations.

Our ability to use our federal and state net operating losses to offset potential future taxable income and related income taxes that would otherwise be due is dependent upon our generation of future taxable income, including where our state losses are subject to expiration, before such state net operating losses expire, and we cannot predict with certainty when, or whether, we will generate sufficient taxable income to use all of our net operating losses. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), contains rules that impose an annual limitation on the ability of a company with federal net operating loss carryforwards that undergoes an ownership change, which is generally any change in ownership of more than 50% of its stock (by value) over a three-year period, to utilize its federal net operating loss carryforwards in years after the ownership change. These rules generally operate by focusing on ownership changes among holders owning directly or indirectly 5% or more of the shares of stock of a company or any change in ownership arising from a new issuance of shares of stock by such company. If a company’s income in any year is less than the annual limitation prescribed by Section 382 of the Code, the unused portion of such limitation amount may be carried forward to increase the limitation in subsequent tax years.

If we were to undergo an ownership change as a result of future transactions involving our common stock, including a follow-on offering of our common stock or purchases or sales of common stock between 5% holders, our ability to use our federal net operating loss carryforwards may be subject to limitation under Section 382 of the Code. If our federal net operating losses become subject to the limitation under Section 382 of the Code, we may be unable to fully utilize our federal net operating loss carryforwards to offset our taxable income, if any, in future years, which could have a negative impact on our financial position and results of operations.

In addition to the aforementioned federal income tax implications pursuant to Section 382 of the Code, most states follow the general provisions of Section 382 of the Code, either explicitly or implicitly resulting in separate state net operating loss limitations. Any limitation on our ability to use our state net operating loss carryforwards could also have a negative impact on our financial position and results of operations.

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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.

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	May 11, 2020	/s/ THOMAS P. CHAMBERS
		Thomas P. Chambers
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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INDEX OF EXHIBITS



Exhibit Number		Description of Document
10.1		Separation Agreement, dated December 6, 2019, between Kosmos Energy, LLC and Paul Nobel.
10.2		Separation Agreement, dated November 12, 2019, between Kosmos Energy, LLC and Eric Haas.

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

Kosmos Energy - 10-Q quarterly report FY2020 Q1

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