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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

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

 

For the quarterly period ended June 30, 2022

☐			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 August 4, 2022
Common Shares, $0.01 par value						455,841,255

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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			3
Item 1. Financial Statements			7
Consolidated Balance Sheets			7
Consolidated Statements of Operations			8
Consolidated Statements of Stockholders’ Equity			9
Consolidated Statements of Cash Flows			10
Notes to Consolidated Financial Statements			11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
Item 3. Quantitative and Qualitative Disclosures about Market Risk			44
Item 4. Controls and Procedures			45
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			46
Item 1A. Risk Factors			46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			46
Item 3. Defaults Upon Senior Securities			46
Item 4. Mine Safety Disclosures			46
Item 5. Other Information			46
Item 6. Exhibits			46
Signatures			47
Index to Exhibits			48

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

 

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

 

“2D seismic data”						Two‑dimensional seismic data, serving as interpretive data that allows a view of a vertical cross‑section beneath a prospective area.
“3D seismic data”						Three‑dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
“ANP-STP”						Agencia Nacional Do Petroleo De Sao Tome E Principe.
“API”						A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus, lighter petroleum liquids will have a higher API than heavier ones.
“Asset Coverage Ratio”						The “Asset Coverage Ratio” as defined in the GoM Term Loan means, as of each March 31, June 30, September 30 and December 31 of each Fiscal Year, commencing December 31, 2020, the ratio of (a) Total PDP PV-10 (as defined in the GoM Term Loan) as of such date to (b) outstanding principal amount of Loans (as defined in the GoM Term Loan) as of such date.
“ASC”						Financial Accounting Standards Board Accounting Standards Codification.
“ASU”						Financial Accounting Standards Board Accounting Standards Update.
“Barrel” or “Bbl”						A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.
“BBbl”						Billion barrels of oil.
“BBoe”						Billion barrels of oil equivalent.
“Bcf”						Billion cubic feet.
“Boe”						Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.
“BOEM”						Bureau of Ocean Energy Management.
“Boepd”						Barrels of oil equivalent per day.
“Bopd”						Barrels of oil per day.
“BP”						BP p.l.c. and related subsidiaries.
“Bwpd”						Barrels of water per day.
“Corporate Revolver”						Prior to March 31, 2022, this term refers to the Revolving Credit Facility Agreement dated November 23, 2012 (as amended or as amended and restated from time to time), and on or after March 31, 2022, this term refers to the new Revolving Credit Facility Agreement dated March 31, 2022.
“COVID-19”						Coronavirus disease 2019.
“Debt cover ratio”						The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long‑term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.
“Developed acreage”						The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development”						The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.
“DST”						Drill stem test.
“Dry hole” or “Unsuccessful well”						A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
“DT”						Deepwater Tano.

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“EBITDAX”						Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results.
“ESG”						Environmental, social, and governance.
“ESP”						Electric submersible pump.
“E&P”						Exploration and production.
“Facility”						Facility agreement dated March 28, 2011 (as amended or as amended and restated from time to time).
“FASB”						Financial Accounting Standards Board.
“Farm‑in”						An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and/or for taking on a portion of future costs or other performance by the assignee as a condition of the assignment.
“Farm‑out”						An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of future costs and/or other work as a condition of the assignment.
“FEED”						Front End Engineering Design.
“Field life cover ratio”						The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
“FLNG”						Floating liquefied natural gas.
“FPS”						Floating production system.
“FPSO”						Floating production, storage and offloading vessel.
“GAAP”						Generally Accepted Accounting Principles in the United States of America.
“GEPetrol”						Guinea Equatorial De Petroleos.
“GHG”						Greenhouse gas.
“GJFFDP”						Greater Jubilee Full Field Development Plan.
“GNPC”						Ghana National Petroleum Corporation.
“GoM Term Loan”						Senior Secured Term Loan Credit Agreement dated September 30, 2020.
“Greater Tortue Ahmeyim”						Ahmeyim and Guembeul discoveries.
“GTA UUOA”						Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
“HLS”						Heavy Louisiana Sweet.
“Jubilee UUOA”						Unitization and Unit Operating Agreement covering the Jubilee Unit.
“Interest cover ratio”						The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.
“LNG”						Liquefied natural gas.
“Loan life cover ratio”						The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
“LSE”						London Stock Exchange.
“LTIP”						Long Term Incentive Plan.
“MBbl”						Thousand barrels of oil.
“MBoe”						Thousand barrels of oil equivalent.

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“Mcf”						Thousand cubic feet of natural gas.
“Mcfpd”						Thousand cubic feet per day of natural gas.
“MMBbl”						Million barrels of oil.
“MMBoe”						Million barrels of oil equivalent.
“MMBtu”						Million British thermal units.
“MMcf”						Million cubic feet of natural gas.
“MMcfd”						Million cubic feet per day of natural gas.
“MMTPA”						Million metric tonnes per annum.
“Natural gas liquid” or “NGL”						Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.
“NYSE”						New York Stock Exchange.
“Petroleum contract”						A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.
“Petroleum system”						A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.
“Plan of development” or “PoD”						A written document outlining the steps to be undertaken to develop a field.
“Productive well”						An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
“Prospect(s)”						A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.
“Proved reserves”						Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S‑X 4‑10(a)(2).
“Proved developed reserves”						Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“Proved undeveloped reserves”						Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
“RSC”						Ryder Scott Company, L.P.
“SEC”						Securities and Exchange Commission.
“7.125% Senior Notes”						7.125% Senior Notes due 2026.
“7.750% Senior Notes”						7.750% Senior Notes due 2027.
“7.500% Senior Notes”						7.500% Senior Notes due 2028.
“Shelf margin”						The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
“Shell”						Royal Dutch Shell and related subsidiaries.
“Stratigraphy”						The study of the composition, relative ages and distribution of layers of sedimentary rock.
“Stratigraphic trap”						A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.
“Structural trap”						A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.

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“Structural‑stratigraphic trap”						A structural‑stratigraphic trap is a combination trap with structural and stratigraphic features.
“Submarine fan”						A fan‑shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.
“TAG GSA”						TEN Associated Gas - Gas Sales Agreement.
“TEN”						Tweneboa, Enyenra and Ntomme.
“Three‑way fault trap”						A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.
“Tortue Phase 1 SPA”						Greater Tortue Ahmeyim Agreement for a Long Term Sale and Purchase of LNG.
“Trafigura”						Trafigura Group PTD, Ltd. and related subsidiaries including Trafigura Trading LLC.
“Trap”						A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
“Trident”						Trident Energy.
“Undeveloped acreage”						Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.
“WCTP”						West Cape Three Points.

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

			June 30, 2022						December 31, 2021
			(Unaudited)
Assets
Current assets:
Cash and cash equivalents			$	223,327					$	131,620
Restricted cash			27						42,971
Receivables:
Joint interest billings, net			38,788						36,908
Oil sales			230,717						134,004
Other			20,952						6,614
Inventories			154,484						165,247
Prepaid expenses and other			21,988						18,899
Derivatives			—						5,689
Total current assets			690,283						541,952
Property and equipment:
Oil and gas properties, net			4,025,752						4,177,323
Other property, net			6,575						6,664
Property and equipment, net			4,032,327						4,183,987
Other assets:
Restricted cash			305						305
Long-term receivables			180,180						191,150
Deferred financing costs, net of accumulated amortization of $12,103 and $19,912 at June 30, 2022 and December 31, 2021, respectively			5,800						1,090
Derivatives			1,988						1,026
Other			20,307						21,141
Total assets			$	4,931,190					$	4,940,651
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable			$	286,730					$	184,403
Accrued liabilities			352,055						250,670
Current maturities of long-term debt			30,000						30,000
Derivatives			197,172						65,879
Total current liabilities			865,957						530,952
Long-term liabilities:
Long-term debt, net			2,280,625						2,590,495
Derivatives			14,758						6,298
Asset retirement obligations			270,176						322,237
Deferred tax liabilities			582,973						711,038
Other long-term liabilities			254,335						250,394
Total long-term liabilities			3,402,867						3,880,462
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2022 and December 31, 2021			—						—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 500,016,474 and 496,152,331 issued at June 30, 2022 and December 31, 2021, respectively			5,000						4,962
Additional paid-in capital			2,488,192						2,473,674
Accumulated deficit			(1,593,819)						(1,712,392)
Treasury stock, at cost, 44,263,269 shares at June 30, 2022 and December 31, 2021, respectively			(237,007)						(237,007)
Total stockholders’ equity			662,366						529,237
Total liabilities and stockholders’ equity			$	4,931,190					$	4,940,651

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

 (Unaudited)

 

			Three Months Ended												Six Months Ended
			June 30,												June 30,
			2022						2021						2022						2021
Revenues and other income:
Oil and gas revenue			$	620,368					$	384,045					$	1,279,383					$	560,519
Gain on sale of assets			471						—						471						26
Other income, net			43						74						95						144
Total revenues and other income			620,882						384,119						1,279,949						560,689
Costs and expenses:
Oil and gas production			90,189						115,803						214,892						161,555
Facilities insurance modifications, net			(384)						1,270						6,752						1,941
Exploration expenses			89,565						9,289						101,441						17,470
General and administrative			24,624						21,728						50,417						44,169
Depletion, depreciation and amortization			121,679						151,161						280,648						227,702
Interest and other financing costs, net			29,382						39,326						62,521						63,854
Derivatives, net			75,204						111,921						357,376						214,382
Other expenses, net			(3,528)						(2,659)						(1,102)						809
Total costs and expenses			426,731						447,839						1,072,945						731,882
Income (loss) before income taxes			194,151						(63,720)						207,004						(171,193)
Income tax expense (benefit)			76,978						(6,533)						88,431						(23,238)
Net income (loss)			$	117,173					$	(57,187)					$	118,573					$	(147,955)
Net income (loss) per share:
Basic			$	0.26					$	(0.14)					$	0.26					$	(0.36)
Diluted			$	0.25					$	(0.14)					$	0.25					$	(0.36)
Weighted average number of shares used to compute net income (loss) per share:
Basic			455,512						408,131						454,811						409,828
Diluted			475,645						408,131						473,471						409,828

 

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
2022:
Balance as of December 31, 2021			496,152						$	4,962					$	2,473,674					$	(1,712,392)					$	(237,007)					$	529,237
Dividends			—						—						12						—						—						12
Equity-based compensation			—						—						8,425						—						—						8,425
Restricted stock units			3,377						33						(33)						—						—						—
Tax withholdings on restricted stock units			—						—						(2,753)						—						—						(2,753)
Net income			—						—						—						1,400						—						1,400
Balance as of March 31, 2022			499,529						4,995						2,479,325						(1,710,992)						(237,007)						536,321
Dividends			—						—						(14)						—						—						(14)
Equity-based compensation			—						—						8,886						—						—						8,886
Restricted stock units			487						5						(5)						—						—						—
Tax withholdings on restricted stock units			—						—						—						—						—						—
Net income			—						—						—						117,173						—						117,173
Balance as of June 30, 2022			500,016						$	5,000					$	2,488,192					$	(1,593,819)					$	(237,007)					$	662,366
2021:
Balance as of December 31, 2020			449,718						$	4,497					$	2,307,220					$	(1,634,556)					$	(237,007)					$	440,154
Dividends			—						—						90						—						—						90
Equity-based compensation			—						—						8,327						—						—						8,327
Restricted stock units			2,408						24						(24)						—						—						—
Tax withholdings on restricted stock units			—						—						(1,018)						—						—						(1,018)
Net loss			—						—						—						(90,768)						—						(90,768)
Balance as of March 31, 2021			452,126						$	4,521					$	2,314,595					$	(1,725,324)					$	(237,007)					$	356,785
Dividends			—						—						29						—						—						29
Equity-based compensation			—						—						7,634						—						—						7,634
Restricted stock awards and units			540						6						(6)						—						—						—
Tax withholdings on restricted stock units															(19)																		(19)
Net loss			—						—						—						(57,187)						—						(57,187)
Balance as of June 30, 2021			452,666						$	4,527					$	2,322,233					$	(1,782,511)					$	(237,007)					$	307,242

 

See accompanying notes.

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KOSMOS ENERGY LTD.

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 (In thousands)

 (Unaudited)

			Six Months Ended June 30,
			2022						2021
Operating activities
Net income (loss)			$	118,573					$	(147,955)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)			285,909						232,893
Deferred income taxes			(83,432)						(69,485)
Unsuccessful well costs and leasehold impairments			73,662						4,865
Change in fair value of derivatives			367,374						223,159
Cash settlements on derivatives, net (including $(212.9) million and $(87.4) million on commodity hedges during 2022 and 2021)			(223,618)						(96,615)
Equity-based compensation			17,129						15,889
Gain on sale of assets			(471)						(26)
Loss on extinguishment of debt			192						15,223
Other			(3,742)						(666)
Changes in assets and liabilities:
Increase in receivables			(103,589)						(13,365)
Increase in inventories			(9,398)						(6,552)
(Increase) decrease in prepaid expenses and other			(4,261)						1,467
Increase in accounts payable			78,179						51,158
Increase in accrued liabilities			95,679						32,265
Net cash provided by operating activities			608,186						242,255
Investing activities
Oil and gas assets			(320,787)						(290,539)
Acquisition of oil and gas properties			(21,205)						—
Proceeds on sale of assets			118,693						1,932
Notes receivable from partners			(11,428)						(36,181)
Net cash used in investing activities			(234,727)						(324,788)
Financing activities
Borrowings under long-term debt			—						100,000
Payments on long-term debt			(315,000)						(400,000)
Net proceeds from issuance of senior notes			—						444,375
Tax withholdings on restricted stock units			(2,753)						(1,037)
Dividends			(655)						(444)
Deferred financing costs			(6,288)						(17,062)
Net cash provided by (used in) financing activities			(324,696)						125,832
Net increase in cash, cash equivalents and restricted cash			48,763						43,299
Cash, cash equivalents and restricted cash at beginning of period			174,896						149,764
Cash, cash equivalents and restricted cash at end of period			$	223,659					$	193,063
Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest			$	46,262					$	44,540
Income taxes, net of refund received			$	137,099					$	22,056

 

See accompanying notes.

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KOSMOS ENERGY LTD.

 

Notes to Consolidated Financial Statements

(Unaudited)

 

1. Organization

 

Kosmos Energy Ltd. changed our jurisdiction of incorporation from Bermuda to the State of Delaware in December 2018 as a holding company for Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise.

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

 

2. Accounting Policies

 

General

 

The interim consolidated financial statements included in this report are unaudited and, in the opinion of management, include all adjustments of a normal recurring nature necessary for a fair presentation of the results for the interim periods. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The interim consolidated financial statements were prepared in accordance with the requirements of the SEC for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by GAAP have been condensed or omitted from these interim consolidated financial statements. These interim consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2021, included in our annual report on Form 10-K.

Reclassifications

 

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

Cash, Cash Equivalents and Restricted Cash 

			June 30, 2022						December 31, 2021
			(In thousands)
Cash and cash equivalents			$	223,327					$	131,620
Restricted cash - current			27						42,971
Restricted cash - long-term			305						305
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows			$	223,659					$	174,896

 

Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. When our net leverage ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes and the 7.500% Senior Notes plus the Corporate Revolver or the

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Facility, whichever is greater. As of March 31, 2022 our net leverage ratio was below 2.50x, therefore in May 2022, we released $59.1 million from restricted cash upon submission of the net leverage test as of March 31, 2022. As of June 30, 2022 our net leverage ratio remained below 2.50x.

 

Inventories

 

Inventories consisted of $143.3 million and $149.5 million of materials and supplies and $11.2 million and $15.7 million of hydrocarbons as of June 30, 2022 and December 31, 2021, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value.

 

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

Revenue Recognition

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

    

    Oil and gas revenue is composed of the following:

			Three Months Ended June 30,												Six Months Ended June 30,
			2022						2021						2022						2021
			(In thousands)
Revenues from contract with customer - Equatorial Guinea			$	113,608					$	84,699					$	222,353					$	111,131
Revenues from contract with customer - Ghana			325,078						196,536						742,185						255,886
Revenues from contract with customers - U.S. Gulf of Mexico			183,046						107,890						324,843						202,279
Provisional oil sales contracts			(1,364)						(5,080)						(9,998)						(8,777)
Oil and gas revenue			$	620,368					$	384,045					$	1,279,383					$	560,519

Concentration of Credit Risk

Our revenue can be materially affected by current economic conditions and the price of oil and natural gas. However, based on the current demand for crude oil and natural gas and the fact that alternative purchasers are available, we believe that the loss of our marketing agents and/or any of the purchasers identified by our marketing agents would not have a long‑term material adverse effect on our financial position or results of operations. The continued economic disruption and volatility in the global and industry-wide markets resulting from the COVID-19 pandemic, Russia’s invasion of Ukraine, a potential global recession, and other varying macroeconomic conditions 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.

3. Acquisitions and Divestitures

Following the closing of the acquisition of Anadarko WCTP Company (“Anadarko WCTP”) in the fourth quarter of 2021, Kosmos’ interest in the Jubilee Unit Area and the TEN fields offshore Ghana were 42.1% and 28.1%, respectively. Under the DT Block Joint Operating Agreement, certain joint venture partners have pre-emption rights in the Jubilee Unit Area and the TEN fields. In November 2021, we received notice from Tullow Oil plc (“Tullow”) and PetroSA that they intend to exercise their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. After execution of definitive transaction documentation and receipt of governmental approvals, Kosmos concluded the pre-emption transaction with Tullow in March 2022. Following the completion of the pre-emption by Tullow, Kosmos’ interest in the Jubilee Unit Area decreased from 42.1% to 38.6% and Kosmos’ interest in the TEN fields decreased from 28.1% to 20.4%. Tullow paid Kosmos $118.2 million in cash

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consideration after post closing adjustments for the pre-emption. During the first quarter of 2022, our oil and gas properties, net balance was reduced by $175.5 million, which includes the cash proceeds and net liabilities transferred to the purchaser as a result of concluding the Tullow pre-emption transaction. The difference in the net book value of the proved property, net liabilities transferred and adjusted purchase price qualified for treatment as a recovery of cost and normal retirement under ASC 932, which resulted in no gain or loss being recognized.

For PetroSA, the pre-emption process is ongoing and remains subject to execution of definitive agreements and required government approvals. Following completion of the pre-emption for PetroSA, Kosmos' ultimate interests in the Jubilee Unit Area and TEN fields would be reduced to 38.3% and 19.8%, respectively.

In March 2022, Kosmos completed the acquisition of an additional 5.5% interest in the Winterfell area in Green Canyon Blocks 943, 944, 987 and 988, offshore U.S. Gulf of Mexico, and an additional 1.5% interest in Green Canyon blocks 899 and 900 for $9.6 million.

In June 2022, Kosmos completed the acquisition of an additional 5.9% interest in the Kodiak oil field from Marubeni by exercising our preferential right to purchase, which increased our working interest from 29.1% to 35.0%. As consideration for the acquisition, Kosmos paid approximately $21.2 million in cash with additional deferred payments of $7.8 million for a total purchase price of approximately $29.0 million The purchase price was based on an initial purchase price of $38.3 million reduced by certain purchase adjustments totaling approximately $9.3 million. The purchase price allocation was based on the estimated fair value of identifiable assets acquired and liabilities assumed primarily comprised of $27.1 million of oil and gas properties, net.

In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Mines and Hydrocarbons of Equatorial Guinea to extend the Block G petroleum contract term harmonizing the expiration of the Ceiba Field and Okume Complex production licenses (from 2029 and 2034 respectively) to 2040. As part of the extension, during the second quarter of 2022, Kosmos paid a signature bonus and agreed to undertake a work program including the drilling of three development wells on Block G in either the Ceiba Field or Okume Complex and the drilling of one exploration well in Block S offshore Equatorial Guinea.

In June 2022, at the conclusion of the second exploration period, Block C12 offshore Mauritania was relinquished.

4. Joint Interest Billings and Long-term Receivables

 

Joint Interest Billings

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

 

In Ghana, the foreign contractor group funded GNPC’s 5% share of the TEN development costs. The foreign contractor group is being reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of June 30, 2022 and December 31, 2021, the current portions of the joint interest billing receivables due from GNPC for the TEN fields development costs were $7.9 million and $7.9 million, respectively, and the long-term portions were $19.3 million and $20.9 million, respectively.

Notes Receivables    

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal obligating us to finance a portion of the respective national oil company’s share of certain development costs incurred through first gas production for Greater Tortue Ahmeyim Phase 1, currently targeted in the third quarter of 2023. Kosmos’ share for the two agreements combined is currently estimated at approximately $240.0 million, which is to be repaid with interest through the national oil companies’ share of future revenues. As of June 30, 2022 and December 31, 2021, the balance due from the national oil companies was $160.9 million and $145.2 million, respectively, which is classified as Long-term receivables on our consolidated balance sheets. Interest income on the long-term notes receivable was $2.3 million and $1.9 million for the three months ended June 30, 2022 and 2021, respectively, and $4.3 million and $3.6 million for the six months ended June 30, 2022 and 2021, respectively.

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Other Long-term Receivables

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

As a result of the above transactions entered into by BP Operator, Kosmos recognized a Long-term receivable of $200.2 million from BP Operator for our share of the consideration paid from BP Buyer to and held by BP Operator as well as a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Tortue FPSO. As of June 30, 2022, this Long-term receivable has been non-cash settled against obligations payable to BP Operator, which included $132.4 million and $67.8 million of non-cash capital expenditures during the fourth quarter of 2021 and the first quarter of 2022, respectively. These non-cash impacts are excluded from the statement of cash flows.

5. Property and Equipment

 

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

 

			June 30, 2022						December 31, 2021
			(In thousands)
Oil and gas properties:
Proved properties			$	6,872,341					$	6,725,453
Unproved properties			405,711						451,454
Total oil and gas properties			7,278,052						7,176,907
Accumulated depletion			(3,252,300)						(2,999,584)
Oil and gas properties, net			4,025,752						4,177,323
Other property			60,359						58,598
Accumulated depreciation			(53,784)						(51,934)
Other property, net			6,575						6,664
Property and equipment, net			$	4,032,327					$	4,183,987

 

We recorded depletion expense of $114.7 million and $145.1 million for the three months ended June 30, 2022 and 2021, respectively, and $266.4 million and $215.8 million for the six months ended June 30, 2022 and 2021, respectively. During the six months ended June 30, 2022 our oil and gas properties, net balance was reduced by $175.5 million as a result of concluding the Tullow pre-emption transaction in March 2022, $64.2 million as a result of the write-off of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the C8 license to exploration expense, offset by additions of $36.9 million related to the acquisition of an additional working interest in the Kodiak oil field and the extension of the Block G licenses in Equatorial Guinea in the second quarter of 2022. See Note 3 — Acquisitions and Divestitures and Note 6 — Suspended Well Costs.

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6. Suspended Well Costs

 

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the six months ended June 30, 2022.

 

			June 30, 2022
			(In thousands)
Beginning balance			$	218,180
Additions to capitalized exploratory well costs pending the determination of proved reserves			16,849
Reclassification due to determination of proved reserves			—
Capitalized exploratory well costs charged to expense			(63,176)
Ending balance			$	171,853

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

 

			June 30, 2022						December 31, 2021
			(In thousands, except project counts)
Exploratory well costs capitalized for a period of one year or less			$	—					$	20,903
Exploratory well costs capitalized for a period of one to three years			62,406						30,389
Exploratory well costs capitalized for a period of four to six years			109,447						166,888
Ending balance			$	171,853					$	218,180
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year			3						3

 

As of June 30, 2022, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal, the Asam discovery in Block S offshore Equatorial Guinea, and the Winterfell discovery in Green Canyon Block 944 in the U.S. Gulf of Mexico.

 

BirAllah and Orca Discoveries — In November 2015, we completed the Marsouin-1 exploration well in the northern part of Block C8 offshore Mauritania, which encountered hydrocarbon pay. During the fourth quarter of 2019, we completed the nearby Orca-1 exploration well which encountered hydrocarbon pay. The BirAllah and Orca discoveries are being analyzed as a joint development. During the second quarter of 2022, the partnership continued progressing appraisal studies, maturing concept design. In June 2022, the exploration period of Block C8 offshore Mauritania expired. As a result, during the second quarter of 2022 we wrote off all of the capitalized costs, or $64.2 million, related to the BirAllah and Orca discoveries incurred under the C8 license to exploration expense. The partnership and the government of Mauritania are currently in the process of finalizing a new Production Sharing Contract (“PSC”) covering these discoveries.

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. In July 2021, the current phase of the Cayar Block exploration license was extended up to an additional three years to 2024. The Yakaar and Teranga discoveries are being analyzed as a joint development. During the second quarter of 2022, we continued progressing appraisal studies and maturing concept design. Following additional evaluation, a decision regarding commerciality is expected to be made.

Asam Discovery — In October 2019, we completed the S-5 exploration well offshore Equatorial Guinea, which encountered hydrocarbon pay. In July 2020, an appraisal plan was approved by the government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and work is currently ongoing to integrate all available data into models to

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establish the scale of the discovered resource. The active phase of the Block S exploration license is currently set to expire in December 2022. During the second quarter of 2022, engineering continued to progress concepts around required subsea infrastructure necessary for a subsea tieback. Once the appraisal plan involving this work is complete, a decision regarding commerciality will be made.

Winterfell Discovery — In January 2021, we drilled the Winterfell-1 exploration well located in Green Canyon Block 944 in the U.S. Gulf of Mexico, which encountered hydrocarbon pay. In January 2022, we drilled the Winterfell-2 appraisal well which encountered hydrocarbon pay. The field development plan has been submitted to partners for approval.

7. Debt

 

			June 30, 2022						December 31, 2021
			(In thousands)
Outstanding debt principal balances:
Facility			$	700,000					$	1,000,000
7.125% Senior Notes			650,000						650,000
7.750% Senior Notes			400,000						400,000
7.500% Senior Notes			450,000						450,000
GoM Term Loan			160,000						175,000
Total			2,360,000						2,675,000
Unamortized deferred financing costs and discounts			(49,375)						(54,505)
Total debt, net			2,310,625						2,620,495
Less: Current maturities of long-term debt			(30,000)						(30,000)
Long-term debt, net			$	2,280,625					$	2,590,495

__________________________________

Facility

 

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of June 30, 2022, borrowings under the Facility totaled $700.0 million and the undrawn availability under the facility was $550.0 million. During the six months ended June 30, 2022, the Company made principal repayments totaling $300.0 million on the Facility including $100.0 million with the proceeds from the Tullow pre-emption transaction. See Note 3 — Acquisitions and Divestitures. Final maturity of the Facility is in March 2027. As part of the last amendment to the Facility in May 2021, the Company incurred $15.2 million for loss on extinguishment of debt during the second quarter of 2021. In April 2022, during the Spring 2022 redetermination, the Company’s lending syndicate approved a borrowing base capacity in excess of the facility size of $1.25 billion. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Company’s production assets in Ghana (excluding the additional interests in Jubilee and TEN acquired in the acquisition of Anadarko WCTP in October 2021) and Equatorial Guinea.

When our net leverage ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes and the 7.500% Senior Notes plus the Corporate Revolver or the Facility, whichever is greater. As of March 31, 2022 our net leverage ratio was below 2.50x, and therefore, we released $59.1 million from restricted cash in May 2022 upon submission of the net leverage test as of March 31, 2022. As of June 30, 2022 our net leverage ratio remained below 2.50x.

We were in compliance with the financial covenants contained in the Facility as of March 31, 2022 (the most recent assessment date). The Facility, as amended, contains customary cross default provisions.

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 Corporate Revolver

On March 31, 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement resulting in the following changes to the terms:

•The total size of the Corporate Revolver is reduced from $400 million to $250 million.

•The maturity date is extended from May 2022 to December 31, 2024.

•Borrowings under the Corporate Revolver now bear interest at a rate equal to the secured overnight financing rate administered by the Federal Reserve Bank of New York plus a credit adjustment spread plus a 7.0% margin plus mandatory costs, if applicable.

•Addition of a negative pledge covenant over the participating interests held by the Company’s wholly-owned subsidiary, Kosmos Energy Ghana Investments, in the WCTP and DT blocks offshore Ghana.

•As the Corporate Revolver is intended to continue to largely remain undrawn, the Company is required to use the proceeds from any capital markets and loan transactions to first repay any drawn outstanding balance under the Corporate Revolver and the Company is subject to a cash sweep of at least 50% of the Company’s Excess Cash (as defined in the Corporate Revolver) to pay outstanding balances as of March 31 or September 30 in any calendar year.

The Company capitalized $6.1 million of deferred financing costs associated with entering into the new revolving credit facility, which will be amortized over the term of the new revolving credit facility. As of June 30, 2022, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs.

We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2022 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. 

7.125% Senior Notes due 2026

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

The 7.125% Senior Notes mature on April 4, 2026. Interest is payable in arrears each April 4 and October 4, commencing on October 4, 2019. The 7.125% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver, 7.750% Senior Notes and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.125% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, the 7.750% Senior Notes and the 7.500% Senior Notes. The 7.125% Senior Notes contain customary cross default provisions.

7.750% Senior Notes due 2027

In October 2021, the Company issued $400.0 million of 7.750% Senior Notes and received net proceeds of approximately $395.0 million after deducting fees. We used the net proceeds, together with cash on hand, to refinance the $400.0 million Bridge Notes (which were issued during in the fourth quarter of 2021 in connection with the completion of the acquisition of Anadarko WCTP) and to pay expenses related to the issuance of the 7.750% Senior Notes.

The 7.750% Senior Notes mature on May 1, 2027. Interest is payable in arrears each May 1 and November 1, commencing on May 1, 2022. The 7.750% 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, the 7.125% Senior Notes and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.750% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by

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certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, the 7.125% Senior Notes and the 7.500% Senior Notes. The 7.750% Senior Notes contain customary cross default provisions.

7.500% Senior Notes due 2028

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

The 7.500% Senior Notes mature on March 1, 2028. Interest is payable in arrears each March 1 and September 1, commencing on September 1, 2021. The 7.500% Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver, the 7.125% Senior Notes and the 7.750% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.500% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the Corporate Revolver, and the 7.125% Senior Notes and the 7.750% Senior Notes. The 7.500% Senior Notes contain customary cross default provisions.

GoM Term Loan    

In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to $100.0 million subject to certain conditions. The GoM Term Loan bears interest at an effective rate of approximately 6% per annum and matures in 2025, with quarterly principal repayments having started since the fourth quarter of 2021. As of June 30, 2022, $30.0 million of the total $160.0 million outstanding under the GoM Term Loan have been classified within Current maturities of long-term debt on our consolidated balance sheet. We were in compliance with the covenants, representations and warranties contained in the GoM Term Loan as of March 31, 2022 (the most recent assessment date). The GoM Term Loan contains customary cross default provisions as well as maturity acceleration provisions if certain Permitted Guaranteed Facilities are not refinanced prior to scheduled maturity.

Principal Debt Repayments

At June 30, 2022, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows: 

			Payments Due by Year
			Total						2022(2)						2023						2024						2025						2026						Thereafter
			(In thousands)
Principal debt repayments(1)			$	2,360,000					$	15,000					$	30,000					$	30,000					$	254,011					$	1,002,418					$	1,028,571

__________________________________

(1)Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as of June 30, 2022 are based on our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

(2)Represents payments for the period July 1, 2022 through December 31, 2022.

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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 June 30,												Six Months Ended June 30,
			2022						2021						2022						2021
			(In thousands)
Interest expense			$	43,016					$	35,740					$	86,178					$	67,175
Amortization—deferred financing costs			2,591						2,620						5,261						5,191
Loss on extinguishment of debt			—						15,223						192						15,223
Capitalized interest			(19,187)						(11,063)						(35,326)						(19,704)
Deferred interest			10						70						(1,440)						(124)
Interest income			(3,344)						(4,247)						(4,884)						(6,072)
Other, net			6,296						983						12,540						2,165
Interest and other financing costs, net			$	29,382					$	39,326					$	62,521					$	63,854

8. Derivative Financial Instruments

 

We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.

 

We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurement.

 

Oil Derivative Contracts

 

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of June 30, 2022. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.

																								Weighted Average Price per Bbl
																								Net Deferred
																								Premium
																								Payable/												Sold
Term						Type of Contract						Index						MBbl						(Receivable)												Put						Floor						Ceiling
2022:
Jul — Dec						Three-way collars						Dated Brent						2,250						$	0.64											$	43.33					$	56.67					$	76.91
Jul — Dec						Three-way collars						NYMEX WTI						500						1.45												50.00						65.00						85.00
Jul — Dec						Two-way collars						Dated Brent						3,000						1.22												—						62.50						83.33
Jul — Dec						Sold calls(1)						Dated Brent						790						—												—						—						60.00
2023:
Jan — Dec						Three-way collars						Dated Brent						2,000						0.92												47.50						65.00						95.25
Jan — Dec						Two-way collars						Dated Brent						2,000						2.50												—						75.00						125.00

__________________________________

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

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The following tables disclose the Company’s derivative instruments as of June 30, 2022 and December 31, 2021, and gain/(loss) from derivatives during the three and six months ended June 30, 2022 and 2021, respectively:

 

												Estimated Fair Value
												Asset (Liability)
Type of Contract						Balance Sheet Location						June 30, 2022						December 31, 2021
												(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity						Derivatives assets—current						$	—					$	5,689
Provisional oil sales						Receivables: Oil Sales						(129)						(853)
Commodity						Derivatives assets—long-term						1,988						1,026
Derivative liabilities:
Commodity						Derivatives liabilities—current						(197,172)						(65,879)
Commodity						Derivatives liabilities—long-term						(14,758)						(6,298)
Total derivatives not designated as hedging instruments												$	(210,071)					$	(66,315)

												Amount of Gain/(Loss)												Amount of Gain/(Loss)
												Three Months Ended												Six Months Ended
												June 30,												June 30,
Type of Contract						Location of Gain/(Loss)						2022						2021						2022						2021
												(In thousands)
Derivatives not designated as hedging instruments:
Provisional oil sales						Oil and gas revenue						$	(1,364)					$	(5,080)					$	(9,998)					$	(8,777)
Commodity						Derivatives, net						(75,204)						(111,921)						(357,376)						(214,382)
Total derivatives not designated as hedging instruments												$	(76,568)					$	(117,001)					$	(367,374)					$	(223,159)

Offsetting of Derivative Assets and Derivative Liabilities

 

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of June 30, 2022 and December 31, 2021, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

9. Fair Value Measurements

 

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

 

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

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

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

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2022 and December 31, 2021, for each fair value hierarchy level: 

			Fair Value Measurements Using:
			Quoted Prices in
			Active Markets for						Significant Other						Significant
			Identical Assets						Observable Inputs						Unobservable Inputs
			(Level 1)						(Level 2)						(Level 3)						Total
			(In thousands)
June 30, 2022
Assets:
Commodity derivatives			$	—					$	1,988					$	—					$	1,988
Provisional oil sales			—						(129)						—						(129)
Liabilities:
Commodity derivatives			—						(211,930)						—						(211,930)
Total			$	—					$	(210,071)					$	—					$	(210,071)
December 31, 2021
Assets:
Commodity derivatives			$	—					$	6,715					$	—					$	6,715
Provisional oil sales			—						(853)						—						(853)
Liabilities:
Commodity derivatives			—						(72,177)						—						(72,177)
Total			$	—					$	(66,315)					$	—					$	(66,315)

 

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

 

Commodity Derivatives

 

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

 

Provisional Oil Sales

 

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

 

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Debt

 

The following table presents the carrying values and fair values at June 30, 2022 and December 31, 2021:

 

			June 30, 2022												December 31, 2021
			Carrying Value						Fair Value						Carrying Value						Fair Value
			(In thousands)
7.125% Senior Notes			$	645,125					$	554,164					$	644,572					$	632,587
7.750% Senior Notes			395,504						335,176						395,131						386,428
7.500% Senior Notes			445,222						372,938						444,892						424,688
GoM Term Loan			160,000						160,000						175,000						175,000
Facility			700,000						700,000						1,000,000						1,000,000
Total			$	2,345,851					$	2,122,278					$	2,659,595					$	2,618,703

 

The carrying values of our 7.125% Senior Notes, 7.750% Senior Notes and 7.500% Senior Notes represent the principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes, 7.750% Senior Notes and 7.500% Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying values of the GoM Term Loan and Facility approximate fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods.

Nonrecurring Fair Value Measurements - Long-lived assets

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

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

During the three and six months ended June 30, 2022 and 2021, the Company did not recognize impairment of proved oil and gas properties as no impairment indicators were identified. If we experience declines in oil pricing expectations in the future, 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.

 

10. Equity-based Compensation

 

Restricted Stock Units

 

We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $8.7 million and $7.6 million during the three months ended June 30, 2022 and 2021, respectively, and $17.1 million and $15.9 million during the six months ended June 30, 2022 and 2021, respectively. The total tax benefit for the three months ended June 30, 2022 and 2021 was $1.5 million and $1.5 million, respectively, and $2.9 million and $2.9 million during the six months ended June 30, 2022 and 2021, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $(0.5) million and $0.2 million for the three months ended June 30, 2022 and 2021, respectively, and $0.7 million and $4.8 million during the six months ended June 30, 2022 and 2021, respectively. The fair value of awards vested during the three months ended June 30, 2022 and 2021 was $4.0 million and $1.8 million, respectively, and $21.3 million and $8.4 million during the six months ended June 30, 2022 and 2021, respectively. The Company granted restricted stock units with service vesting criteria and a combination of market and service vesting criteria under the LTIP. Substantially all of these grants vest over three years. Upon vesting, restricted stock units become issued and outstanding stock

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The following table reflects the outstanding restricted stock units as of June 30, 2022:

 

									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, 2021			4,696						$	3.88					11,233						$	5.28
Granted(1)			2,767						4.68						3,370						6.97
Forfeited(1)			(130)						3.91						(386)						6.11
Vested			(2,364)						4.18						(2,136)						5.98
Outstanding at June 30, 2022			4,969						4.18						12,081						5.60

__________________________________

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

 

As of June 30, 2022, total equity-based compensation to be recognized on unvested restricted stock units is $37.2 million over a weighted average period of 1.90 years. At June 30, 2022, the Company had approximately 6.0 million shares that remain available for issuance under the LTIP.

 

For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value ranged from $1.06 to $12.33 per award. The Monte Carlo simulation model utilized multiple input variables that determined the probability of satisfying the market condition stipulated in the award grant and calculated the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 50.0% to 104.8%. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.2% to 2.5%.

11. Income Taxes

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

During the six months ended June 30, 2022, our deferred tax liability decreased by approximately $128.1 million. Approximately $44.6 million of the decrease is the result of concluding the Tullow pre-emption transaction in March 2022. See Note 3 - Acquisitions and Divestitures. The remaining $83.5 million decrease in our deferred tax liability is the result of originating deferred tax assets, primarily related to mark to market losses on commodity derivative contracts and the recognition of other net deferred tax liabilities, primarily related to book depreciation and depletion expense in excess of amount reported for income tax purposes.

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

 

			Three Months Ended June 30,												Six Months Ended June 30,
			2022						2021						2022						2021
			(In thousands)
United States			$	52,381					$	(16,798)					$	61,664					$	(38,640)
Foreign			141,770						(46,922)						145,340						(132,553)
Income (loss) before income taxes			$	194,151					$	(63,720)					$	207,004					$	(171,193)

 

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For the three months ended, June 30, 2022 and 2021, our effective tax rate was 40% and 10%, respectively. For the six months ended, June 30, 2022 and 2021, our effective tax rate was 43% and 14%, respectively. For the three and six months ended June 30, 2022 and 2021, our overall effective tax rates were impacted by:

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

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

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

12. Net Income (Loss) Per Share

 

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

			Three Months Ended												Six Months Ended
			June 30,												June 30,
			2022						2021						2022						2021
			(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders			$	117,173					$	(57,187)					$	118,573					$	(147,955)
Denominator:
Weighted average number of shares outstanding:
Basic			455,512						408,131						454,811						409,828
Restricted stock units(1)			20,133						—						18,660						—
Diluted			475,645						408,131						473,471						409,828
Net income (loss) per share:
Basic			$	0.26					$	(0.14)					$	0.26					$	(0.36)
Diluted			$	0.25					$	(0.14)					$	0.25					$	(0.36)

__________________________________

(1)We excluded restricted stock units of 0.1 million and 15.7 million for the three months ended June 30, 2022 and 2021, respectively, and 0.1 million and 14.7 million for the six months ended June 30, 2022 and 2021, respectively, from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.

13. Commitments and Contingencies

 

From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.

 

We have a commitment to drill three development wells and one exploration well in Equatorial Guinea. In Mauritania, we have a $200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue FPSO.

Performance Obligations

As of June 30, 2022 and December 31, 2021, the Company had performance bonds totaling $195.5 million and $195.5 million, respectively, for our supplemental bonding requirements stipulated by the BOEM and $9.7 million and $3.5 million, respectively, to third parties related to costs anticipated for the plugging and abandonment of certain wells and the removal of certain facilities in our U.S. Gulf of Mexico fields.

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14. Additional Financial Information

 

Accrued Liabilities

 

Accrued liabilities consisted of the following: 

			June 30, 2022						December 31, 2021
			(In thousands)
Accrued liabilities:
Exploration, development and production			$	91,404					$	61,881
Revenue payable			40,553						31,986
Current asset retirement obligations			2,067						3,222
General and administrative expenses			15,804						27,980
Interest			38,994						31,117
Income taxes			104,193						69,392
Taxes other than income			1,239						2,854
Derivatives			55,246						19,302
Other			2,555						2,936
			$	352,055					$	250,670

Asset Retirement Obligations

 

The following table summarizes the changes in the Company's asset retirement obligations as of and during the six months ended June 30, 2022:

			June 30, 2022
			(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations			$	325,459
Liabilities incurred during period			10,452
Liabilities settled during period			(10,531)
Revisions in estimated retirement obligations			(65,552)
Accretion expense			12,415
Ending asset retirement obligations			$	272,243

During the six months ended June 30, 2022 our asset retirement obligations were reduced by approximately $10.0 million as a result of concluding the Tullow pre-emption transaction in March 2022 and approximately $66.2 million as a result of the extension of the Block G licenses in Equatorial Guinea. See Note 3 — Acquisitions and Divestitures.

Other Expenses, Net

 

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

			Three Months Ended June 30,												Six Months Ended June 30,
			2022						2021						2022						2021
			(In thousands)
Loss on disposal of inventory			$	68					$	215					$	285					$	582
Loss on asset retirement obligations liability settlements			238						357						620						386
Restructuring charges			(9)						18						(4)						837
Other, net			(3,825)						(3,249)						(2,003)						(996)
Other expenses, net			$	(3,528)					$	(2,659)					$	(1,102)					$	809

 

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15. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At June 30, 2022, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the U.S. Gulf of Mexico. To assess performance of the reporting segments, the Chief Operating Decision Maker reviews capital expenditures. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each area is presented below:

			Ghana(2)						Equatorial Guinea						Mauritania/Senegal						U.S. Gulf of Mexico(3)						Corporate & Other						Eliminations						Total
			(In thousands)
Three months ended June 30, 2022
Revenues and other income:
Oil and gas revenue			$	326,091					$	111,231					$	—					$	183,046					$	—					$	—					$	620,368
Gain on sale of assets			—						—						—						471						—						—						471
Other income, net			—						—						—						484						108,192						(108,633)						43
Total revenues and other income			326,091						111,231						—						184,001						108,192						(108,633)						620,882
Costs and expenses:
Oil and gas production			37,776						25,839						—						26,574						—						—						90,189
Facilities insurance modifications, net			(384)						—						—						—						—						—						(384)
Exploration expenses			1,903						1,366						74,975						10,520						801						—						89,565
General and administrative			3,444						1,415						2,270						3,433						47,491						(33,429)						24,624
Depletion, depreciation and amortization			62,376						15,050						61						43,753						439						—						121,679
Interest and other financing costs, net(1)			14,260						(607)						(15,662)						2,734						28,657						—						29,382
Derivatives, net			—						—						—						—						75,204						—						75,204
Other expenses, net			66,235						4,894						(1,930)						4,295						(1,818)						(75,204)						(3,528)
Total costs and expenses			185,610						47,957						59,714						91,309						150,774						(108,633)						426,731
Income (loss) before income taxes			140,481						63,274						(59,714)						92,692						(42,582)						—						194,151
Income tax expense (benefit)			49,798						24,719						—						—						2,461						—						76,978
Net income (loss)			$	90,683					$	38,555					$	(59,714)					$	92,692					$	(45,043)					$	—					$	117,173
Consolidated capital expenditures			$	56,128					$	14,074					$	136,615					$	39,940					$	1,534					$	—					$	248,291

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			Ghana(2)						Equatorial Guinea						Mauritania/Senegal						U.S. Gulf of Mexico(3)						Corporate & Other						Eliminations						Total
			(In thousands)
Six months ended June 30, 2022
Revenues and other income:
Oil and gas revenue			$	735,571					$	218,969					$	—					$	324,843					$	—					$	—					$	1,279,383
Gain on sale of assets			—						—						—						471						—						—						471
Other income, net			1						—						—						1,028						423,304						(424,238)						95
Total revenues and other income			735,572						218,969						—						326,342						423,304						(424,238)						1,279,949
Costs and expenses:
Oil and gas production			113,119						48,464						—						53,309						—						—						214,892
Facilities insurance modifications, net			6,752						—						—						—						—						—						6,752
Exploration expenses			1,974						2,976						78,089						17,096						1,306						—						101,441
General and administrative			7,413						3,017						4,266						8,377						94,206						(66,862)						50,417
Depletion, depreciation and amortization			163,786						32,988						115						82,947						812						—						280,648
Interest and other financing costs, net(1)			29,286						(1,088)						(28,501)						5,458						57,366						—						62,521
Derivatives, net			—						—						—						—						357,376						—						357,376
Other expenses, net			316,797						24,017						(1,344)						17,672						(868)						(357,376)						(1,102)
Total costs and expenses			639,127						110,374						52,625						184,859						510,198						(424,238)						1,072,945
Income (loss) before income taxes			96,445						108,595						(52,625)						141,483						(86,894)						—						207,004
Income tax expense (benefit)			34,780						48,049						—						3,102						2,500						—						88,431
Net income (loss)			$	61,665					$	60,546					$	(52,625)					$	138,381					$	(89,394)					$	—					$	118,573
Consolidated capital expenditures			$	(8,057)					$	24,296					$	147,416					$	64,244					$	2,712					$	—					$	230,611
As of June 30, 2022
Property and equipment, net			$	1,661,177					$	389,499					$	1,092,873					$	870,768					$	18,010					$	—					$	4,032,327
Total assets			$	3,127,071					$	1,097,801					$	1,540,896					$	3,605,374					$	18,046,768					$	(22,486,720)					$	4,931,190

______________________________________

(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.

(2)Includes activity related to the interest pre-empted by Tullow prior to the March 17, 2022 closing date of the Tullow pre-emption transaction. Additionally, cash consideration of $118.2 million is included as reduction in Consolidated capital expenditures for the six months ended June 30, 2022.

(3)Includes activity related to our acquisition of an additional interest in the Kodiak oil field commencing June 9, 2022, the acquisition date. Additionally, cash consideration paid of $29.0 million is included in Consolidated capital expenditures for the three and six months ended June 30, 2022.

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			Ghana						Equatorial Guinea						Mauritania/Senegal						U.S. Gulf of Mexico						Corporate & Other						Eliminations						Total
			(In thousands)
Three months ended June 30, 2021
Revenues and other income:
Oil and gas revenue			$	191,826					$	84,329					$	—					$	107,890					$	—					$	—					$	384,045
Other income, net			1						—						—						443						144,426						(144,796)						74
Total revenues and other income			191,827						84,329						—						108,333						144,426						(144,796)						384,119
Costs and expenses:
Oil and gas production			57,313						31,715						—						26,775						—						—						115,803
Facilities insurance modifications, net			1,269						—						—						—						1						—						1,270
Exploration expenses			43						684						1,557						5,418						1,587						—						9,289
General and administrative			2,884						1,251						2,724						3,204						44,539						(32,874)						21,728
Depletion, depreciation and amortization			87,639						19,284						16						43,796						426						—						151,161
Interest and other financing costs, net(1)			8,138						(403)						(12,396)						4,295						39,692						—						39,326
Derivatives, net			—						—						—						—						111,921						—						111,921
Other expenses, net			87,867						13,798						(3,026)						11,048						(425)						(111,921)						(2,659)
Total costs and expenses			245,153						66,329						(11,125)						94,536						197,741						(144,795)						447,839
Income (loss) before income taxes			(53,326)						18,000						11,125						13,797						(53,315)						(1)						(63,720)
Income tax expense (benefit)			(18,120)						11,565						—						—						22						—						(6,533)
Net income (loss)			$	(35,206)					$	6,435					$	11,125					$	13,797					$	(53,337)					$	(1)					$	(57,187)
Consolidated capital expenditures			$	26,011					$	19,669					$	82,672					$	20,219					$	327					$	1,917					$	150,815

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			Ghana						Equatorial Guinea						Mauritania/Senegal						U.S. Gulf of Mexico						Corporate & Other						Eliminations						Total
			(In thousands)
Six months ended June 30, 2021
Revenues and other income:
Oil and gas revenue			$	245,879					$	112,361					$	—					$	202,279					$	—					$	—					$	560,519
Gain on sale of assets			—						—						—						—						26						—						26
Other income, net			1						—						—						772						281,925						(282,554)						144
Total revenues and other income			245,880						112,361						—						203,051						281,951						(282,554)						560,689
Costs and expenses:
Oil and gas production			69,699						43,344						—						48,512						—						—						161,555
Facilities insurance modifications, net			1,940						—						—						—						1						—						1,941
Exploration expenses			75						2,577						3,731						6,566						4,521						—						17,470
General and administrative			5,471						2,302						4,697						8,443						89,644						(66,388)						44,169
Depletion, depreciation and amortization			111,274						28,475						31						87,047						875						—						227,702
Interest and other financing costs, net(1)			20,054						(772)						(22,212)						8,861						59,707						(1,784)						63,854
Derivatives, net			—						—						—						—						214,382						—						214,382
Other expenses, net			158,988						30,867						(2,242)						25,537						2,041						(214,382)						809
Total costs and expenses			367,501						106,793						(15,995)						184,966						371,171						(282,554)						731,882
Income (loss) before income taxes			(121,621)						5,568						15,995						18,085						(89,220)						—						(171,193)
Income tax expense (benefit)			(41,988)						14,199						—						—						4,551						—						(23,238)
Net income (loss)			$	(79,633)					$	(8,631)					$	15,995					$	18,085					$	(93,771)					$	—					$	(147,955)
Consolidated capital expenditures			$	30,635					$	31,093					$	155,424					$	44,486					$	5,726					$	—					$	267,364
As of June 30, 2021
Property and equipment, net			$	1,214,334					$	432,087					$	751,237					$	955,805					$	21,180					$	—					$	3,374,643
Total assets			$	1,290,106					$	797,425					$	1,105,754					$	3,198,153					$	13,985,966					$	(16,374,132)					$	4,003,272

______________________________________

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

			Six Months Ended June 30,
			2022						2021
			(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets			$	320,787					$	290,539
Acquisition of oil and gas properties			21,205						—
Proceeds on sale of assets			(118,693)						(1,932)
Adjustments:
Changes in capital accruals			7,061						(15,830)
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)			27,779						12,605
Capitalized interest			(35,326)						(19,704)
Other			7,798						1,686
Total consolidated capital expenditures			$	230,611					$	267,364

______________________________________

(1)Unsuccessful well costs and leasehold impairments 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, 2021, 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 the U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration program in Equatorial Guinea, Ghana and the U.S. Gulf of Mexico.

The ongoing COVID-19 pandemic that emerged at the beginning of 2020 resulted in travel restrictions, including border closures, travel bans, social distancing restrictions and office closures being ordered in the various countries in which we operate, impacting some of our business operations. These restrictions, together with logistical challenges, have had an impact on the supply chain, resulting in the delay of various operational projects.

Globally, the impacts of COVID-19, Russia’s invasion of Ukraine, potential recession, and other varying macroeconomic conditions has impacted supply and demand for oil and gas, which also resulted in significant variability in oil and gas prices. The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on these commodity prices.

Recent Developments

    

Corporate

Under the terms of our 2020 farm-out agreement with Shell, potential contingent consideration is payable by Shell depending on the results of the first four exploration wells Shell drills in the purchased assets, excluding South Africa. Upon approval of the relevant operating committee of an appraisal plan for submission to the relevant governmental authority for any of those first four exploration wells, Shell will be required to pay Kosmos $50.0 million of consideration for each discovery for which an appraisal plan is approved by the relevant operating committee, capped in the aggregate at a maximum of $100.0 million total. There were two oil discoveries announced in Namibia during the first half of 2022. Under the terms of Shell’s Petroleum Agreement with Namibia, if Shell decides to appraise one or both of the discoveries, an appraisal plan is required to be submitted within 150 days from completion of tests on a discovery well.

Ghana

 

During the second quarter of 2022, Ghana production averaged approximately 97,200 Bopd gross (31,600 Bopd net). Jubilee production averaged approximately 73,600 Bopd gross (27,000 Bopd net), including the impact of the two week planned shutdown of the Jubilee FPSO. Excluding the shutdown, Jubilee production averaged approximately 92,000 Bopd gross. TEN production averaged approximately 23,600 Bopd gross (4,600 Bopd net).

In the second quarter of 2022, the multi-year development drilling program continued to progress with the completion of one producer well and one water injector well in the Jubilee Field. Both wells were successfully brought online in the second quarter of 2022. Following Jubilee completion operations, the drilling rig then moved to the TEN fields and continued operations with the successful completion of one water injector well. In July 2022, the partnership drilled the first of the two riser base wells at TEN to initially define the extent of the Ntomme reservoir supporting the TEN Enhancement Project. The well was drilled to test two separate reservoir objectives and encountered better reservoir quality and thickness than expected but was water bearing. A second well is currently being planned to target a different fairway in a structurally higher setting. The results of the two wells will allow the partnership to high-grade and optimize the future drilling plans for the TEN Enhancement Project. In July 2022, the Jubilee partners completed the transition of the operations & maintenance (O&M) services for the Jubilee FPSO from external provider MODEC, Inc. to Tullow.

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Following the closing of the acquisition of Anadarko WCTP Company (“Anadarko WCTP”) in the fourth quarter of 2021, Kosmos’ interest in the Jubilee Unit Area and the TEN fields offshore Ghana were 42.1% and 28.1%, respectively. Under the DT Block Joint Operating Agreement, certain joint venture partners have pre-emption rights in the Jubilee Unit Area and the TEN fields. In November 2021, we received notice from Tullow Oil plc (“Tullow”) and PetroSA that they intend to exercise their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. After execution of definitive transaction documentation and receipt of governmental approvals, Kosmos concluded the pre-emption transaction with Tullow in March 2022. Following the completion of the pre-emption by Tullow, Kosmos’ interest in the Jubilee Unit Area decreased from 42.1% to 38.6% and Kosmos’ interest in the TEN fields decreased from 28.1% to 20.4%. The net 2022 production impact of the Tullow pre-emption exercise for Kosmos was a reduction of approximately 4,000 barrels of oil per day, based on the March 17, 2022 closing date, and is expected to result in one less Ghana cargo lifting this year and a reduction in 2022 capital expenditure of approximately $30.0 million.

For PetroSA, the pre-emption process is ongoing and remains subject to execution of definitive agreements and required government approvals. Following completion of the pre-emption for PetroSA, Kosmos' ultimate interests in the Jubilee Unit Area and TEN fields would be reduced to 38.3% and 19.8%, respectively.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 20,600 Boepd net (~82% oil) for the second quarter of 2022.

In March 2022, the Company commenced operations to plug back and side-track the original Kodiak #3 infill well located in Mississippi Canyon. The side-tracked well is expected to be online in the third quarter of 2022, with insurance proceeds expected to cover substantially all of the costs incurred to return the Kodiak #3 well to production. In June 2022, Kosmos completed the acquisition of an additional 5.9% interest in the Kodiak oil field from Marubeni by exercising our preferential right to purchase, which increased our working interest from 29.1% to 35.0%. As consideration for the acquisition, Kosmos paid approximately $21.2 million in cash with additional deferred payments of $7.8 million for a total purchase price of approximately $29.0 million.

In January 2021, we announced the Winterfell exploration well encountered approximately 26 meters (85 feet) of net oil pay in two intervals. Winterfell was designed to test a sub-salt Upper Miocene prospect located in Green Canyon Block 944. In January 2022, the Winterfell-2 appraisal well in Green Canyon Block 943 was drilled to evaluate the adjacent fault block to the northwest of the original Winterfell discovery and was designed to test two horizons that were oil bearing in the Winterfell-1 well, with an exploration tail into a deeper horizon. The well discovered approximately 40 meters (120 feet) of net oil pay in the first and second horizons with better oil saturation and porosity than pre-drill expectations. The exploration tail discovered an additional oil-bearing horizon in a deeper reservoir which is also prospective in the blocks immediately to the north. The field development plan has been submitted to the partners for approval, with a final investment decision approval expected by the end of the third quarter of 2022.

In March 2022, Kosmos completed the acquisition of an additional 5.5% interest in the Winterfell area in Green Canyon Blocks 943, 944, 987 and 988 and an additional 1.5% interest in Green Canyon blocks 899 and 900 for $9.6 million. We are currently in discussions with partners to approve the development plan expected in the third quarter of 2022.

In August 2022, the operator of the Helix Producer I (the “HP-I”) production platform disconnected the HP-I for a scheduled dry-dock inspection required by the U.S. Coast Guard. Production from the Tornado field is processed through the HP-I and will remain shut-in while the vessel is undergoing its scheduled dry-dock which is estimated to be approximately 45 days.

In June 2022, we executed, as operator of the Odd Job field, a contract for $131.6 million (gross) with Subsea 7 (US) LLC and OneSubsea LLC to fabricate and install a subsea pump in the Odd Job field. The project commenced in July 2022 with an expected online date around the middle of 2024. Kosmos’ working interest in the Odd Job field is approximately 54.9%.

Equatorial Guinea

    

Production in Equatorial Guinea averaged approximately 31,300 Bopd gross (10,000 Bopd net) in the second quarter of 2022.

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In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Mines and Hydrocarbons of Equatorial Guinea to extend the Block G petroleum contract term harmonizing the expiration of the Ceiba Field and Okume Complex production licenses (from 2029 and 2034 respectively) to 2040. The license extension supports the next phase of investment in the license. As part of the extension, during the second quarter of 2022, Kosmos paid a signature bonus, included in our 2022 capital plan, and agreed to undertake a future work program including the drilling of three development wells on Block G in either the Ceiba Field or Okume Complex and the drilling of one exploration well in Block S offshore Equatorial Guinea.

Mauritania and Senegal

In June 2022, the exploration period of Block C8 offshore Mauritania expired. The partnership and the government of Mauritania are currently in the process of finalizing a new Production Sharing Contract (“PSC”) covering these discoveries. The new PSC is expected to provide two years to submit a development plan covering the BirAllah and/or Orca discoveries with the terms of the new PSC substantially similar to the former PSC for Block C8 with additional provisions for potentially enhanced back-in rights for the Government of Mauritania, local content, SMH’s capacity building and an environmental fund. As a result, during the second quarter of 2022 we wrote off all of the capitalized costs, or $64.2 million, related to the BirAllah and Orca discoveries incurred under the C8 license to exploration expense, however, these costs will still be tax deductible and cost recoverable against our Greater Tortue development.

In June 2022, at the conclusion of the second exploration period, Block C12 offshore Mauritania was relinquished.

Greater Tortue Ahmeyim Unit

Phase 1 of the Greater Tortue project continues to make good progress in 2022 with first gas for the project targeted in the third quarter of 2023. The following milestones were achieved as of the end of the second quarter of 2022 and post quarter-end:

•FLNG: construction and mechanical completion activities continue and commissioning work has begun

•FPSO: mechanical completion activities continue and hull commissioning work has commenced. The operator has been unable to make up the delay from the lockdown of the FPSO yard in April 2022 and the ongoing COVID-19 restrictions in China. As a result, the FPSO sailaway date is now expected to be in the fourth quarter of 2022, with the same high-level of completion prior to sailaway.

•Hub Terminal: All 21 caissons installed. The piling installation is nearing completion and the living quarters platform is currently in transit to site

•Subsea: subsea equipment has begun to arrive in region and installation of the export pipeline has commenced

•Drilling: successfully drilled two of the four wells required for first gas and the third well is in progress

Sao Tome and Principe

In the second quarter of 2022, we received approval for a six month extension to May 2023 for the current exploration phase for Block 5 offshore Sao Tome and Principe.

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Results of Operations

 

All of our results, as presented in the table below, represent operations from Jubilee and TEN fields in Ghana, the U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the three and six months ended June 30, 2022 and 2021 are included in the following tables:

			Three Months Ended June 30,									Six Months Ended June 30,
			2022						2021			2022						2021
			(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)			5,339						5,689			11,569						8,630
Gas (MMcf)			1,252						1,221			2,256						2,547
NGL (MBbl)			129						127			246						254
Total (MBoe)			5,677						6,020			12,191						9,309
Total (Boepd)			62,381						66,150			67,354						51,428
Revenues:
Oil sales			$	604,668					$	377,632		$	1,254,676					$	546,782
Gas sales			10,271						3,679			15,207						8,219
NGL sales			5,429						2,734			9,500						5,518
Total oil and gas revenue			$	620,368					$	384,045		$	1,279,383					$	560,519
Average oil sales price per Bbl			$	113.25					$	66.38		$	108.45					$	63.36
Average gas sales price per Mcf			8.20						3.01			6.74						3.23
Average NGL sales price per Bbl			42.09						21.52			38.62						21.72
Average total sales price per Boe			109.28						63.80			104.94						60.22
Costs:
Oil and gas production, excluding workovers			$	88,120					$	112,301		$	209,343					$	154,793
Oil and gas production, workovers			2,069						3,502			5,549						6,762
Total oil and gas production costs			$	90,189					$	115,803		$	214,892					$	161,555
Depletion, depreciation and amortization			$	121,679					$	151,161		$	280,648					$	227,702
Average cost per Boe:
Oil and gas production, excluding workovers			$	15.52					$	18.66		$	17.17					$	16.63
Oil and gas production, workovers			0.36						0.58			0.46						0.73
Total oil and gas production costs			15.88						19.24			17.63						17.36
Depletion, depreciation and amortization			21.43						25.11			23.02						24.46
Total			$	37.31					$	44.35		$	40.65					$	41.82

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The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of June 30, 2022:

 

			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			—						—						—						—						—						—						7						2.70
TEN(1)			1						0.20						—						—						—						—						7						1.43
Equatorial Guinea
Block S			—						—						—						—						1						0.40						—						—
Okume			—						—						—						—						—						—						1						0.43
U.S. Gulf of Mexico
Winterfell			—						—						—						—						2						0.44						—						—
Kodiak 771 #3			—						—						1						0.35						—						—						—						—
Mauritania / Senegal
Greater Tortue Ahmeyim Unit			—						—						1						0.27						—						—						3						0.80
Senegal Cayar Profond			—						—						—						—						3						0.90						—						—
Total			1						0.20						2						0.62						6						1.74						18						5.36

(1)Includes the NT-10 well which was considered a step out well from an accounting perspective, but was drilled as part of the TEN development plan.

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

 

Three months ended June 30, 2022 compared to three months ended June 30, 2021

 

			Three Months Ended
			June 30,												Increase
			2022						2021						(Decrease)
			(In thousands)
Revenues and other income:
Oil and gas revenue			$	620,368					$	384,045					$	236,323
Gain on sale of assets			471						—						471
Other income, net			43						74						(31)
Total revenues and other income			620,882						384,119						236,763
Costs and expenses:
Oil and gas production			90,189						115,803						(25,614)
Facilities insurance modifications, net			(384)						1,270						(1,654)
Exploration expenses			89,565						9,289						80,276
General and administrative			24,624						21,728						2,896
Depletion, depreciation and amortization			121,679						151,161						(29,482)
Interest and other financing costs, net			29,382						39,326						(9,944)
Derivatives, net			75,204						111,921						(36,717)
Other expenses, net			(3,528)						(2,659)						(869)
Total costs and expenses			426,731						447,839						(21,108)
Income (loss) before income taxes			194,151						(63,720)						257,871
Income tax expense (benefit)			76,978						(6,533)						83,511
Net income (loss)			$	117,173					$	(57,187)					$	174,360

 

Oil and gas revenue.  Oil and gas revenue increased by $236.3 million during the three months ended June 30, 2022, as compared to the three months ended June 30, 2021 primarily as a result of higher average oil prices and our acquisition of additional interests in Ghana during the fourth quarter of 2021, which more than offset the timing of liftings in Equatorial Guinea. We sold 5,677 MBoe at an average realized price per barrel equivalent of $109.28 during the three months ended June 30, 2022 and 6,020 MBoe at an average realized price per barrel equivalent of $63.80 during the three months ended June 30, 2021.

Oil and gas production.  Oil and gas production costs decreased by $25.6 million during the three months ended June 30, 2022, as compared to the three months ended June 30, 2021 primarily as a result of lower production costs per barrel driven by field production mix in our international business units and lower sales volumes due to timing of liftings in Equatorial Guinea.

 

Exploration expenses.  Exploration expenses increased by $80.3 million during the three months ended June 30, 2022, as compared to the three months ended June 30, 2021 primarily as result of the $64.2 million of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania that were written off to exploration expense with the expiration of the exploration period of Block C8, and approximately $14.0 million related to the exit of leases in the U.S. Gulf of Mexico and Mauritania.

Depletion, depreciation and amortization.  Depletion, depreciation and amortization decreased $29.5 million during the three months ended June 30, 2022, as compared with the three months ended June 30, 2021 primarily as a result of field production mix in our international business units and lower overall sales volumes during the quarter.

Interest and other financing costs, net. Interest and other financing costs, net decreased $9.9 million during the three months ended June 30, 2022, as compared with the three months ended June 30, 2021 primarily as a result of $15.2 million for loss on extinguishment of debt during the second quarter of 2021 related to the Facility amendment an $8.0 million increase in

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capitalized interest during 2022, offset by $7.5 million of higher interest expense related to our senior notes issuances in 2021 and $6.0 million of guarantee fees on the Tortue FPSO transaction.

Derivatives, net.  During the three months ended June 30, 2022 and 2021, we recorded a loss of $75.2 million and a loss of $111.9 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.

Income tax expense (benefit). For the three months ended June 30, 2022 and 2021, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

    Six months ended June 30, 2022 compared to six months ended June 30, 2021

			Six Months Ended
			June 30,												Increase
			2022						2021						(Decrease)
			(In thousands)
Revenues and other income:
Oil and gas revenue			$	1,279,383					$	560,519					$	718,864
Gain on sale of assets			471						26						445
Other income, net			95						144						(49)
Total revenues and other income			1,279,949						560,689						719,260
Costs and expenses:
Oil and gas production			214,892						161,555						53,337
Facilities insurance modifications, net			6,752						1,941						4,811
Exploration expenses			101,441						17,470						83,971
General and administrative			50,417						44,169						6,248
Depletion, depreciation and amortization			280,648						227,702						52,946
Interest and other financing costs, net			62,521						63,854						(1,333)
Derivatives, net			357,376						214,382						142,994
Other expenses, net			(1,102)						809						(1,911)
Total costs and expenses			1,072,945						731,882						341,063
Income (loss) before income taxes			207,004						(171,193)						378,197
Income tax expense (benefit)			88,431						(23,238)						111,669
Net income (loss)			$	118,573					$	(147,955)					$	266,528

Oil and gas revenue.  Oil and gas revenue increased by $718.9 million during the six months ended June 30, 2022, as compared to the six months ended June 30, 2021 primarily as a result of higher average oil prices and increased sales volumes related to the timing of liftings in Ghana and our acquisition of additional interests in Ghana during the fourth quarter of 2021. We sold 12,191 MBoe at an average realized price per barrel equivalent of $104.94 during the six months ended June 30, 2022 and 9,309 MBoe at an average realized price per barrel equivalent of $60.22 during the six months ended June 30, 2021.

 

Oil and gas production.  Oil and gas production costs increased by $53.3 million during the six months ended June 30, 2022, as compared to the six months ended June 30, 2021 primarily as a result of higher overall sales volumes across our portfolio.

 

Exploration expenses.  Exploration expenses increased by $84.0 million during the six months ended June 30, 2022, as compared to the six months ended June 30, 2021 primarily a result of the $64.2 million of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania that were written off to exploration expense with the expiration of the exploration period of Block C8, and approximately $15.0 million related to the exit of leases in the U.S. Gulf of Mexico and Mauritania business units.

 

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General and administrative.  General and administrative costs increased by $6.2 million during the six months ended June 30, 2022, as compared with the six months ended June 30, 2021 primarily as a result of increased travel costs and professional fees and increased non-cash equity based compensation expense for the six months ended June 30, 2022.

Depletion, depreciation and amortization.  Depletion, depreciation and amortization increased $52.9 million during the six months ended June 30, 2022, as compared with the six months ended June 30, 2021 primarily as a result of higher overall sales volumes in the current year.

Interest and other financing costs, net.  Interest and other financing costs, net decreased $1.3 million during the six months ended June 30, 2022, as compared to the six months ended June 30, 2021, primarily as a result of $15.2 million for loss on extinguishment of debt during the second quarter of 2021 related to the Facility amendment, increased capitalized interest related to the Greater Tortue Ahmeyim project, offset by increased interest expense on the 7.750% Senior Notes and the 7.500% Senior Notes issued during 2021 and guarantee fees on the Tortue FPSO transaction.

Derivatives, net.  During the six months ended June 30, 2022 and 2021, we recorded a loss of $357.4 million and a loss of $214.4 million, respectively, on our outstanding hedge positions. The changes recorded were a result of changes in the forward curve of oil prices during the respective periods.

 

Income tax expense (benefit). For the six months ended June 30, 2022 and 2021, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

Liquidity and Capital Resources

 

We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to our strategy as a full-cycle exploration and production company. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt, as well as partner carries.

Current oil prices are volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could result in wide fluctuations in future oil prices, which could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program and our current liquidity position support our remaining capital program for 2022.

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Sources and Uses of Cash

 

The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the six months ended June 30, 2022 and 2021:

 

			Six Months Ended
			June 30,
			2022						2021
			(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities			$	608,186					$	242,255
Net proceeds from issuance of senior notes			—						444,375
Borrowings under long-term debt			—						100,000
Proceeds on sale of assets			118,693						1,932
			726,879						788,562
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets			320,787						290,539
Acquisition of oil and gas properties			21,205						—
Notes receivable from partners			11,428						36,181
Payments on long-term debt			315,000						400,000
Purchase of treasury stock			2,753						1,037
Dividends			655						444
Deferred financing costs			6,288						17,062
			678,116						745,263
Increase in cash, cash equivalents and restricted cash			$	48,763					$	43,299

 

Net cash provided by operating activities.  Net cash provided by operating activities for the six months ended June 30, 2022 was $608.2 million compared with net cash provided by operating activities for the six months ended June 30, 2021 of $242.3 million. The increase in cash provided by operating activities in the six months ended June 30, 2022 when compared to the same period in 2021 is primarily a result of increased sales volumes and higher oil prices.

The following table presents our net debt and liquidity as of June 30, 2022:

 

			June 30, 2022
			(In thousands)
Cash and cash equivalents			$	223,327
Restricted cash			332
7.125% Senior Notes			650,000
7.750% Senior Notes			400,000
7.500% Senior Notes			450,000
Borrowings under the Facility			700,000
Borrowings under the GoM Term Loan			160,000
Net debt			$	2,136,341
Availability under the Facility			$	550,000
Availability under the Corporate Revolver			$	250,000
Available borrowings plus cash and cash equivalents			$	1,023,327

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Capital Expenditures and Investments

We expect to incur capital costs as we:

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

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

•    execute appraisal and development activities in Mauritania and Senegal.

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

2022 Capital Program

We estimate we will spend around $700 million of capital for the year ending December 31, 2022, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

•Approximately $225-$275 million related to maintenance activities across our Ghana, Equatorial Guinea and U.S. Gulf of Mexico assets, including infill development drilling and integrity spend

•Approximately $100-$140 million related to growth activities across our Ghana, Equatorial Guinea and U.S. Gulf of Mexico assets, primarily pre-investment for infrastructure required to support production growth in 2023 and beyond

•Approximately $300 million related to development of Phase 1 of Greater Tortue Ahmeyim, net of the Tortue FPSO transaction benefit

•Approximately $30 million related to progressing the appraisal plans of our greater gas resource in Mauritania and Senegal, including Phase 2 of Greater Tortue Ahmeyim, BirAllah and Yakaar-Teranga.

Through June 30, 2022, we have spent approximately $320.3 million on capital expenditures, excluding the offsetting impact of the Tullow and Kodiak pre-empt transactions. This represents a slight increase over our prior estimates due to inflationary impacts we are expecting, largely on the Greater Tortue Ahmeyim development.

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

Significant Sources of Capital

 

Facility

 

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities with a borrowing base calculation that includes value related to the Jubilee, TEN, Ceiba and Okume fields, however, the additional interests in Jubilee and TEN acquired in the October 2021 acquisition of Anadarko WCTP are not included in the borrowing base calculation. During the six months ended June 30, 2022, the Company made principal repayments totaling $300.0 million on the Facility including $100.0 million with the proceeds from the Tullow pre-emption transaction. See Note 3 — Acquisitions and Divestitures. In April 2022, during the Spring 2022 redetermination, the Company’s lending syndicate approved a borrowing base capacity in excess of the facility size of $1.25 billion. As of June 30, 2022, borrowings under the Facility totaled $700.0 million and the undrawn availability under the facility was $550.0 million.

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, 2024, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2027. As of June 30, 2022, we had no letters of credit issued under the Facility.

We have the right to cancel all the undrawn commitments under the amended and restated Facility. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in Ghana and Equatorial Guinea, however, excludes the additional interests in Jubilee and TEN acquired in the acquisition of Anadarko WCTP.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain asset. We were in compliance with the financial covenants contained in the Facility as of March 31, 2022 (the most recent assessment date). The Facility contains customary cross default provisions. 

Corporate Revolver

On March 31, 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement resulting in the following changes to the terms:

•The total size of the Corporate Revolver is reduced from $400 million to $250 million.

•The maturity date is extended from May 2022 to December 31, 2024.

•Borrowings under the Corporate Revolver now bear interest at a rate equal to the secured overnight financing rate administered by the Federal Reserve Bank of New York plus a credit adjustment spread plus a 7.0% margin plus mandatory costs, if applicable.

•Addition of a negative pledge covenant over the participating interests held by the Company’s wholly-owned subsidiary, Kosmos Energy Ghana Investments, in the WCTP and DT blocks offshore Ghana.

•As the Corporate Revolver is intended to continue to largely remain undrawn, the Company is required to use the proceeds from any capital markets and loan transactions to first repay any drawn outstanding balance under the Corporate Revolver and the Company is subject to a cash sweep of at least 50% of the Company’s Excess Cash (as defined in the Corporate Revolver) to pay outstanding balances as of March 31 or September 30 in any calendar year.

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The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. The Company expects the reduced Corporate Revolver size to offset an increase in the margin, resulting in slightly lower interest expenses going forward. As of June 30, 2022, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million.

The available amount is not subject to borrowing base constraints. We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.

 We were in compliance with the financial covenants contained in the Corporate Revolver as of March 31, 2022 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. 

The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility or Corporate Revolver are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility and Corporate Revolver. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition, we periodically review our banking and financing relationships, considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.

Senior Notes

We have three series of senior notes outstanding, which we collectively referred to as the “Senior Notes.” Our 7.125% Senior Notes mature on April 4, 2026, and interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.500% Senior Notes mature on March 1, 2028, and interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 7.750% Senior Notes mature on May 1, 2027, and interest is payable on the 7.750% Senior Notes each May 1 and November 1.

The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equally 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 and the GoM Term Loan). The Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP Acquisition, and on a subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.

GoM Term Loan

In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to $100.0 million subject to certain conditions. As of June 30, 2022, borrowings under the GoM Term Loan totaled $160.0 million. As of June 30, 2022, $30.0 million of the total $160.0 million outstanding under the GoM Term Loan have been classified within Current maturities of long-term debt on our consolidated balance sheet.

The GoM Term Loan contains customary affirmative and negative covenants, including covenants that affect our ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or capital expenditures, among other things. The GoM Term Loan is guaranteed on a senior, secured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets.

The GoM Term Loan includes certain representations and warranties, indemnities and events of default that, subject to certain materiality thresholds and grace periods, arise as a result of a payment default, failure to comply with covenants, material inaccuracy of representation or warranty, and certain bankruptcy or insolvency proceedings. If there is an event of default, all or any portion of the outstanding indebtedness may be immediately due and payable and other rights may be exercised including against the collateral.

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Contractual Obligations

 

The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2022 and the weighted average interest rates expected to be paid on the Facility, Corporate Revolver and GoM Term Loan given current contractual terms and market conditions, and the instrument’s estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not include amortization of deferred financing costs. 

																																																Asset
																																																(Liability)
																																																Fair Value at
						Years Ending December 31,																																										June 30,
						2022(2)						2023						2024						2025						2026						Thereafter						Total(3)						2022
						(In thousands, except percentages)
Fixed rate debt:
7.125% Senior Notes						$	—					$	—					$	—					$	—					$	650,000					$	—					$	650,000					$	554,164
7.750% Senior Notes						—						—						—						—						—						400,000						$	400,000					$	335,176
7.500% Senior Notes						—						—						—						—						—						450,000						450,000						372,938
Variable rate debt:
Weighted average interest rate						6.70		%				7.20		%				7.06		%				7.02		%				7.46		%				7.81		%
Facility(1)						$	—					$	—					$	—					$	169,011					$	352,418					$	178,571					$	700,000					$	700,000
GoM Term Loan						15,000						30,000						30,000						85,000						—						—						160,000						160,000
Total principal debt repayments(1)						$	15,000					$	30,000					$	30,000					$	254,011					$	1,002,418					$	1,028,571					$	2,360,000
Interest & commitment fee payments on long-term debt						90,687						183,245						177,988						161,045						114,832						69,610						797,407
Operating leases(4)						1,985						4,034						4,105						4,176						4,248						10,845						29,393
Purchase obligations(5)						28,470						68,198						34,976						—						—						—						131,644

__________________________________

(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of June 30, 2022. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

(2)Represents the period July 1, 2022 through December 31, 2022.

(3)Does not include our share of operator’s purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts. The Company's liabilities for asset retirement obligations associated with the dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 14 — Additional Financial Information for additional information regarding these liabilities.

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

(5)Represents gross contractual obligations to execute planned future capital projects. Other joint owners in the properties operated by Kosmos will be billed for their working interest share of such costs.

We have a commitment to drill three development wells and one exploration well in Equatorial Guinea. In Mauritania, we have a $200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue FPSO.

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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. 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, 2021.

 

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;

•the impact of Russia’s invasion of Ukraine and the effects it has on the oil and gas industry as a whole, including increased volatility with respect to oil, natural gas and NGL prices and operating and capital expenditures

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

•uncertainties inherent in making estimates of our oil and natural gas data;

•the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;

•projected and targeted capital expenditures and other costs, commitments and revenues;

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

•our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;

•the ability to obtain financing and to comply with the terms under which such financing may be available;

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

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

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

•other competitive pressures;

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

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

•cost of compliance with laws and regulations;

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

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

•environmental liabilities;

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

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

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

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•our vulnerability to severe weather events, including tropical storms and hurricanes in the Gulf of Mexico;

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

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

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

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

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

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

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

Item 3. Qualitative and Quantitative Disclosures About Market Risk

 

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

 

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

 

The following table reconciles the changes that occurred in fair values of our open derivative contracts during the six months ended June 30, 2022: 

			Derivative Contracts Assets (Liabilities)
			Commodities
			(In thousands)
Fair value of contracts outstanding as of December 31, 2021			$	(66,315)
Changes in contract fair value			(367,374)
Contract maturities			223,618
Fair value of contracts outstanding as of June 30, 2022			$	(210,071)

 

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 six months of 2022 ranged between $78.99 and $137.64 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first six months of 2022.

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Commodity Derivative Instruments

 

We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of collars, put options and call options. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase. In addition, a reduction in our ability to access credit could reduce our ability to implement derivative contracts on commercially reasonable terms.

 

Commodity Price Sensitivity

 

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of June 30, 2022. Volumes and weighted average prices are net of any offsetting derivatives entered into. 

																								Weighted Average Price per Bbl																								Asset
																								Net Deferred																														(Liability)
																								Premium																														Fair Value at
																								Payable/												Sold																		June 30,
Term						Type of Contract						Index						MBbl						(Receivable)												Put						Floor						Ceiling						2022(2)
																																																						(In thousands)
2022:
Jul — Dec						Three-way collars						Dated Brent						2,250						$	0.64											$	43.33					$	56.67					$	76.91					$	(67,377)
Jul — Dec						Three-way collars						NYMEX WTI						500						1.45												50.00						65.00						85.00						(8,981)
Jul — Dec						Two-way collars						Dated Brent						3,000						1.22												—						62.50						83.33						(74,333)
Jul — Dec						Sold calls(1)						Dated Brent						790						—												—						—						60.00						(35,435)
2023:
Jan — Dec						Three-way collars						Dated Brent						2,000						0.92												47.50						65.00						95.25						(24,912)
Jan — Dec						Two-way collars						Dated Brent						2,000						2.50												—						75.00						125.00						1,096

__________________________________

(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 June 30, 2022.

At June 30, 2022, our open commodity derivative instruments were in a net liability position of $209.9 million. As of June 30, 2022, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $80.1 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $83.8 million.

 

Interest Rate Sensitivity

 

Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Facility and GoM Term Loan, which as of June 30, 2022 total $0.9 billion and have a weighted average interest rate of 5.1%, are subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. If the floating market rate increased 10% at this level of floating rate debt, we would pay an estimated additional $1.9 million interest expense per year. The commitment fees on the undrawn availability under the Facility and the Corporate Revolver are not subject to changes in interest rates. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. Additionally, a change in the market interest rates could impact interest costs associated with future debt issuances or any future borrowings.

Item 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of

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the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2022, 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” sections of our annual report on Form 10-K for the year ended December 31, 2021, and in our quarterly report on Form 10-Q for the three months ended March 31, 2022.

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			August 8, 2022						/s/ NEAL D. SHAH
									Neal D. Shah
									Senior Vice President and Chief Financial Officer
									(Principal Financial Officer)

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INDEX OF EXHIBITS

 

Exhibit Number						Description of Document
31.1						Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2						Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1						Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2						Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS						XBRL Instance Document
101.SCH						XBRL Taxonomy Extension Schema Document
101.CAL						XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB						XBRL Taxonomy Extension Label Linkbase Document
101.PRE						XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF						XBRL Taxonomy Extension Definition Linkbase Document

___________________________________

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