KOS 10-Q Quarterly Report Sept. 30, 2022

KOSMOS ENERGY LTD.

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kos-20220930

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 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 November 3, 2022
Common Shares, $0.01 par value						455,893,501

Table of Contents

TABLE OF CONTENTS

Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its wholly owned subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.


			Page
PART I. FINANCIAL INFORMATION

Glossary and Select Abbreviations			3

Item 1. Financial Statements			7
Consolidated Balance Sheets			7
Consolidated Statements of Operations			8
Consolidated Statements of Stockholders’ Equity			9
Consolidated Statements of Cash Flows			10
Notes to Consolidated Financial Statements			11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			31
Item 3. Quantitative and Qualitative Disclosures about Market Risk			45
Item 4. Controls and Procedures			46

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			47
Item 1A. Risk Factors			47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			47
Item 3. Defaults Upon Senior Securities			47
Item 4. Mine Safety Disclosures			47
Item 5. Other Information			47
Item 6. Exhibits			48
Signatures			48
Index to Exhibits			49

Table of Contents

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.

Table of Contents


“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.

Table of Contents


“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.
“SMH”						Societe Mauritanienne des Hydrocarbures
“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.

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

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30, 2022		December 31, 2021
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	231,565	$	131,620
Restricted cash	27		42,971
Receivables:
Joint interest billings, net	40,643		36,908
Oil sales	67,604		134,004

Other	22,385		6,614
Inventories	150,284		165,247
Prepaid expenses and other	23,402		18,899
Derivatives	11,879		5,689
Total current assets	547,789		541,952
Property and equipment:
Oil and gas properties, net	4,132,962		4,177,323
Other property, net	5,705		6,664
Property and equipment, net	4,138,667		4,183,987
Other assets:

Restricted cash	305		305
Long-term receivables	201,196		191,150
Deferred financing costs, net of accumulated amortization of $ 12,683 and $ 19,912 at September 30, 2022 and December 31, 2021, respectively	5,220		1,090

Derivatives	8,646		1,026
Other	19,589		21,141
Total assets	$	4,921,412	$	4,940,651
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	272,767	$	184,403
Accrued liabilities	252,196		250,670
Current maturities of long-term debt	30,000		30,000
Derivatives	37,477		65,879
Total current liabilities	592,440		530,952
Long-term liabilities:
Long-term debt, net	2,275,769		2,590,495
Derivatives	2,147		6,298
Asset retirement obligations	275,867		322,237
Deferred tax liabilities	629,755		711,038
Other long-term liabilities	251,943		250,394
Total long-term liabilities	3,435,481		3,880,462
Stockholders’ equity:
Preference shares, $ 0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2022 and December 31, 2021	—		—
Common stock, $ 0.01 par value; 2,000,000,000 authorized shares; 500,104,524 and 496,152,331 issued at September 30, 2022 and December 31, 2021, respectively	5,001		4,962
Additional paid-in capital	2,497,062		2,473,674
Accumulated deficit	( 1,371,565 )		( 1,712,392 )
Treasury stock, at cost, 44,263,269 shares at September 30, 2022 and December 31, 2021, respectively	( 237,007 )		( 237,007 )
Total stockholders’ equity	893,491		529,237
Total liabilities and stockholders’ equity	$	4,921,412	$	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				Nine Months Ended
	September 30,				September 30,
	2022		2021		2022		2021
Revenues and other income:
Oil and gas revenue	$	456,056	$	198,936	$	1,735,439	$	759,455
Gain on sale of assets	—		1,538		471		1,564
Other income, net	48		66		143		210
Total revenues and other income	456,104		200,540		1,736,053		761,229
Costs and expenses:
Oil and gas production	62,372		50,316		277,264		211,871
Facilities insurance modifications, net	494		1,554		7,246		3,495
Exploration expenses	17,215		23,982		118,656		41,452
General and administrative	24,007		22,459		74,424		66,628
Depletion, depreciation and amortization	106,313		64,914		386,961		292,616

Interest and other financing costs, net	29,796		26,873		92,317		90,727
Derivatives, net	( 113,842 )		38,224		243,534		252,606
Other expenses, net	( 218 )		194		( 1,320 )		1,003
Total costs and expenses	126,137		228,516		1,199,082		960,398
Income (loss) before income taxes	329,967		( 27,976 )		536,971		( 199,169 )
Income tax expense (benefit)	107,713		621		196,144		( 22,617 )
Net income (loss)	$	222,254	$	( 28,597 )	$	340,827	$	( 176,552 )

Net income (loss) per share:
Basic	$	0.49	$	( 0.07 )	$	0.75	$	( 0.43 )
Diluted	$	0.47	$	( 0.07 )	$	0.72	$	( 0.43 )

Weighted average number of shares used to compute net income (loss) per share:
Basic	455,840		408,520		455,158		408,009
Diluted	476,431		408,520		474,820		408,009

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
Dividends	—	—		—		—		—		—
Equity-based compensation	—	—		8,871		—		—		8,871
Restricted stock units	89	1		( 1 )		—		—		—
Tax withholdings on restricted stock units	—	—		—		—		—		—
Net income	—	—		—		222,254		—		222,254
Balance as of September 30, 2022	500,105	$	5,001	$	2,497,062	$	( 1,371,565 )	$	( 237,007 )	$	893,491

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
Dividends	—	—		21		—		—		21
Equity-based compensation	—	—		8,149		—		—		8,149
Restricted stock units	339	3		( 3 )		—		—		—
Tax withholdings on restricted stock units	—	—		( 63 )		—		—		( 63 )
Net loss	—	—		—		( 28,597 )		—		( 28,597 )
Balance as of September 30, 2021	453,005	$	4,530	$	2,330,337	$	( 1,811,108 )	$	( 237,007 )	$	286,752

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2022		2021
Operating activities
Net income (loss)	$	340,827	$	( 176,552 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	394,799		300,404
Deferred income taxes	( 37,445 )		( 68,366 )
Unsuccessful well costs and leasehold impairments	83,086		16,772

Change in fair value of derivatives	257,112		259,289
Cash settlements on derivatives, net (including $( 289.9 ) million and $( 142.9 ) million on commodity hedges during 2022 and 2021)	( 304,328 )		( 150,255 )
Equity-based compensation	25,896		24,011
Gain on sale of assets	( 471 )		( 1,564 )
Loss on extinguishment of debt	192		15,223
Other	( 5,940 )		( 2,763 )
Changes in assets and liabilities:
Decrease in receivables	54,035		1,537
Increase in inventories	( 4,377 )		( 24,280 )
Increase in prepaid expenses and other	( 5,704 )		( 4,800 )
Increase (decrease) in accounts payable	64,216		( 35,545 )
Increase (decrease) in accrued liabilities	1,338		( 9,270 )
Net cash provided by operating activities	863,236		143,841
Investing activities
Oil and gas assets	( 543,349 )		( 377,850 )
Acquisition of oil and gas properties	( 21,205 )		—
Proceeds on sale of assets	118,703		5,327
Notes receivable from partners	( 28,188 )		( 41,712 )
Net cash used in investing activities	( 474,039 )		( 414,235 )
Financing activities
Borrowings under long-term debt	—		250,000
Payments on long-term debt	( 322,500 )		( 400,000 )
Net proceeds from issuance of senior notes	—		444,375
Tax withholdings on restricted stock units	( 2,753 )		( 1,100 )
Dividends	( 655 )		( 512 )
Deferred financing costs	( 6,288 )		( 17,291 )
Net cash provided by (used in) financing activities	( 332,196 )		275,472
Net increase in cash, cash equivalents and restricted cash	57,001		5,078
Cash, cash equivalents and restricted cash at beginning of period	174,896		149,764
Cash, cash equivalents and restricted cash at end of period	$	231,897	$	154,842

Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest	$	79,787	$	61,046
Income taxes, net of refund received	$	195,782	$	67,581

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 pursue a 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


	September 30, 2022		December 31, 2021
	(In thousands)
Cash and cash equivalents	$	231,565	$	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	$	231,897	$	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 2.50 x, 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 2.50 x, 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 September 30, 2022 our net leverage ratio remained below 2.50 x.

Inventories

Inventories consisted of $ 129.0 million and $ 149.5 million of materials and supplies and $ 21.3 million and $ 15.7 million of hydrocarbons as of September 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. During the third quarter of 2022, Kosmos sold $ 14.9 million of material and supplies inventory in exchange for cash.

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

Revenue Recognition

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

Oil and gas revenue is composed of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(In thousands)
Revenues from contract with customer - Equatorial Guinea	$	41,178	$	34,247	$	263,532	$	145,378
Revenues from contract with customer - Ghana	301,855		65,969		1,044,039		321,855
Revenues from contract with customers - U.S. Gulf of Mexico	116,603		96,626		441,446		298,905
Provisional oil sales contracts	( 3,580 )		2,094		( 13,578 )		( 6,683 )
Oil and gas revenue	$	456,056	$	198,936	$	1,735,439	$	759,455

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 approximately $ 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. Additionally, in September 2022, Kosmos completed the acquisition of an additional 3.2 % interest in the Winterfell area in Green Canyon Blocks 943, 944, 987 and 988 and an additional 1.4 % interest in Green Canyon Blocks 899 and 900 for $ 6.6 million. As a result of the two transactions, our participating interests in the Green Canyon Blocks 943, 944, 987, and 988 is now 25.0 % and our participating interests in the Green Canyon Blocks 899 and 900 is now 37.8 %.

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, 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 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 September 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 $ 21.1 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 September 30, 2022 and December 31, 2021, the balance due from the national oil companies was $ 179.3 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 $ 2.5 million and $ 1.8 million for the three months ended September 30, 2022 and 2021, respectively, and $ 6.8 million and $ 5.4 million for the nine months ended September 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 Greater Tortue FPSO. As of September 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:


	September 30, 2022		December 31, 2021
	(In thousands)
Oil and gas properties:
Proved properties	$	7,050,725	$	6,725,453
Unproved properties	434,574		451,454
Total oil and gas properties	7,485,299		7,176,907
Accumulated depletion	( 3,352,337 )		( 2,999,584 )
Oil and gas properties, net	4,132,962		4,177,323

Other property	60,419		58,598
Accumulated depreciation	( 54,714 )		( 51,934 )
Other property, net	5,705		6,664

Property and equipment, net	$	4,138,667	$	4,183,987

We recorded depletion expense of $ 100.0 million and $ 58.8 million for the three months ended September 30, 2022 and 2021, respectively, and $ 366.4 million and $ 274.6 million for the nine months ended September 30, 2022 and 2021, respectively. During the nine months ended September 30, 2022 our oil and gas properties, net balance was reduced by approximately $ 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 $ 53.1 million related to the acquisition of an additional working interest in the Kodiak oil field, the extension of the Block G licenses in Equatorial Guinea, and the acquisitions of additional participating interests in the Winterfell area. 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 nine months ended September 30, 2022.


	September 30, 2022
	(In thousands)
Beginning balance	$	218,180
Additions to capitalized exploratory well costs pending the determination of proved reserves	22,037
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	( 62,818 )
Ending balance	$	177,399

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


	September 30, 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	65,890		30,389
Exploratory well costs capitalized for a period of four to six years	111,509		166,888
Ending balance	$	177,399	$	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 September 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. 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. In October 2022, the partnership and the government of Mauritania executed a new Production Sharing Contract (“PSC”) covering these discoveries, which will become effective upon being published in Mauritania’s Official Gazette.

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 2022, we have 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 2022, engineering has continued to progress concepts around required subsea infrastructure necessary for a subsea tieback. Following additional evaluation, a decision regarding commerciality is expected to 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. During the third quarter of 2022, the Field Development Plan for the Winterfell field was approved by all partners. Execution of a host facility production handling agreement and midstream export agreement are in process.

7. Debt


	September 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	152,500		175,000
Total	2,352,500		2,675,000
Unamortized deferred financing costs and discounts	( 46,731 )		( 54,505 )
Total debt, net	2,305,769		2,620,495
Less: Current maturities of long-term debt	( 30,000 )		( 30,000 )
Long-term debt, net	$	2,275,769	$	2,590,495

__________________________________

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of September 30, 2022, borrowings under the Facility totaled $ 700.0 million and the undrawn availability under the facility was $ 550.0 million. During the nine months ended September 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 October 2022, during the Fall 2022 redetermination, the Company’s lending syndicate approved a borrowing base of approximately $ 1.24 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 2.50 x, 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 2.50 x, 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 September 30, 2022 our net leverage ratio remained below 2.50 x.

We were in compliance with the financial covenants contained in the Facility as of September 30, 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 September 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 September 30, 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 in 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.

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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 7.125 % 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 6.6 % per annum and matures in 2025, with quarterly principal repayments having started since the fourth quarter of 2021. As of September 30, 2022, $ 30.0 million of the total $ 152.5 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 September 30, 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 September 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)	$	2,352,500	$	7,500	$	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 September 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 October 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 September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(In thousands)
Interest expense	$	45,448	$	36,055	$	131,626	$	103,229
Amortization—deferred financing costs	2,577		2,597		7,838		7,788
Loss on extinguishment of debt	—		—		192		15,223
Capitalized interest	( 22,163 )		( 12,252 )		( 57,489 )		( 31,956 )
Deferred interest	4		( 600 )		( 1,436 )		( 724 )
Interest income	( 2,956 )		( 2,237 )		( 7,840 )		( 8,309 )
Other, net	6,886		3,310		19,426		5,476
Interest and other financing costs, net	$	29,796	$	26,873	$	92,317	$	90,727

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 September 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:
Oct — Dec	Three-way collars	Dated Brent	1,125	$	0.64	$	43.33	$	56.67	$	76.91
Oct — Dec	Three-way collars	NYMEX WTI	250	1.45		50.00		65.00		85.00
Oct — Dec	Two-way collars	Dated Brent	1,500	1.22		—		62.50		83.33
Oct — Dec	Sold calls(1)	Dated Brent	395	—		—		—		60.00
2023:
Jan — Dec	Three-way collars	Dated Brent	4,000	1.21		48.75		70.00		106.38
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

In October 2022, we entered into Dated Brent three-way collar contracts for 1.0 MMBbl from January 2023 through December 2023 with a sold put price of $ 50.00 per barrel, a floor price of $ 75.00 per barrel and a ceiling price of $ 110.00 per barrel. In addition, we entered into Dated Brent two-way collar contracts for 2.0 MMBbl from January 2023 through December 2023 with a floor price of $ 70.00 per barrel and a ceiling price of $ 110.00 per barrel.

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


		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2022		December 31, 2021
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity	Derivatives assets—current	$	11,879	$	5,689
Provisional oil sales	Receivables: Oil Sales	—		( 853 )
Commodity	Derivatives assets—long-term	8,646		1,026
Derivative liabilities:
Commodity	Derivatives liabilities—current	( 37,477 )		( 65,879 )
Commodity	Derivatives liabilities—long-term	( 2,147 )		( 6,298 )
Total derivatives not designated as hedging instruments		$	( 19,099 )	$	( 66,315 )


		Amount of Gain/(Loss)				Amount of Gain/(Loss)
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
Type of Contract	Location of Gain/(Loss)	2022		2021		2022		2021
		(In thousands)
Derivatives not designated as hedging instruments:
Provisional oil sales	Oil and gas revenue	$	( 3,580 )	$	2,094	$	( 13,578 )	$	( 6,683 )
Commodity	Derivatives, net	113,842		( 38,224 )		( 243,534 )		( 252,606 )
Total derivatives not designated as hedging instruments		$	110,262	$	( 36,130 )	$	( 257,112 )	$	( 259,289 )

Offsetting of Derivative Assets and Derivative Liabilities

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of September 30, 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 September 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)
September 30, 2022
Assets:
Commodity derivatives	$	—	$	20,525	$	—	$	20,525
Provisional oil sales	—		—		—		—

Liabilities:
Commodity derivatives	—		( 39,624 )		—		( 39,624 )

Total	$	—	$	( 19,099 )	$	—	$	( 19,099 )
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 September 30, 2022 and December 31, 2021:


	September 30, 2022				December 31, 2021
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
7.125 % Senior Notes	$	645,409	$	534,034	$	644,572	$	632,587
7.750 % Senior Notes	395,697		320,992		395,131		386,428
7.500 % Senior Notes	445,391		352,598		444,892		424,688
GoM Term Loan	152,500		152,500		175,000		175,000

Facility	700,000		700,000		1,000,000		1,000,000
Total	$	2,338,997	$	2,060,124	$	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 nine months ended September 30, 2022 and 2021, the Company did no t recognize impairment of proved oil and gas properties as no impairment indicators were identified. If we experience significant declines in oil pricing expectations in the future, significant increases in our estimated future expenditures or a significant 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 $ 8.8 million and $ 8.1 million during the three months ended September 30, 2022 and 2021, respectively, and $ 25.9 million and $ 24.0 million during the nine months ended September 30, 2022 and 2021, respectively. The total tax benefit for the three months ended September 30, 2022 and 2021 was $ 1.5 million and $ 1.5 million, respectively, and $ 4.4 million and $ 4.5 million during the nine months ended September 30, 2022 and 2021, respectively. Additionally, we recorded a net tax shortfall related to equity-based compensation of nil and $ 1.5 million for the three months ended September 30, 2022 and 2021, respectively, and $ 0.7 million and $ 6.3 million during the nine months ended September 30, 2022 and 2021, respectively. The fair value of awards vested during the three months ended September 30, 2022 and 2021 was $ 0.5 million and $ 1.0 million, respectively, and $ 21.9 million and $ 9.4 million during the nine months ended September 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 September 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)	2,793	4.70		3,378	6.97
Forfeited(1)	( 145 )	3.91		( 389 )	6.19
Vested	( 2,413 )	4.20		( 2,175 )	5.98
Outstanding at September 30, 2022	4,931	4.18		12,047	5.61

__________________________________

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

As of September 30, 2022, total equity-based compensation to be recognized on unvested restricted stock units is $ 28.5 million over a weighted average period of 1.78 years. At September 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 nine months ended September 30, 2022, our deferred tax liability decreased by approximately $ 81.3 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 $ 36.7 million decrease in our deferred tax liability is primarily the result of originating and reversing temporary differences.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(In thousands)
United States	$	16,168	$	( 19,129 )	$	77,832	$	( 57,769 )
Foreign	313,799		( 8,847 )		459,139		( 141,400 )
Income (loss) before income taxes	$	329,967	$	( 27,976 )	$	536,971	$	( 199,169 )

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For the three months ended, September 30, 2022 and 2021, our effective tax rate was 33 % and 2 %, respectively. For the nine months ended, September 30, 2022 and 2021, our effective tax rate was 37 % and 11 %, respectively. For the three and nine months ended September 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				Nine Months Ended
	September 30,				September 30,
	2022		2021		2022		2021
	(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders	$	222,254	$	( 28,597 )	$	340,827	$	( 176,552 )




Denominator:
Weighted average number of shares outstanding:
Basic	455,840		408,520		455,158		408,009
Restricted stock units(1)	20,591		—		19,662		—
Diluted	476,431		408,520		474,820		408,009
Net income (loss) per share:
Basic	$	0.49	$	( 0.07 )	$	0.75	$	( 0.43 )
Diluted	$	0.47	$	( 0.07 )	$	0.72	$	( 0.43 )

__________________________________

(1) We excluded restricted stock units of 0.2 million and 15.4 million for the three months ended September 30, 2022 and 2021, respectively, and 0.1 million and 15.0 million for the nine months ended September 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 September 30, 2022 and December 31, 2021, the Company had performance bonds totaling $ 203.7 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:


	September 30, 2022		December 31, 2021
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	54,901	$	61,881
Revenue payable	21,830		31,986
Current asset retirement obligations	3,234		3,222
General and administrative expenses	23,886		27,980
Interest	28,800		31,117
Income taxes	105,963		69,392
Taxes other than income	1,547		2,854
Derivatives	6,311		19,302
Other	5,724		2,936
	$	252,196	$	250,670

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Asset Retirement Obligations

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


	September 30, 2022
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	325,459
Liabilities incurred during period	11,964
Liabilities settled during period	( 10,532 )
Revisions in estimated retirement obligations	( 65,552 )
Accretion expense	17,762
Ending asset retirement obligations	$	279,101

During the nine months ended September 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 in May 2022. See Note 3 — Acquisitions and Divestitures.

Other Expenses, Net

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(In thousands)
(Gain) loss on disposal of inventory	$	( 821 )	$	( 280 )	$	( 536 )	$	302
Loss on asset retirement obligations liability settlements	—		58		620		444
Restructuring charges	—		( 127 )		( 4 )		710
Other, net	603		543		( 1,400 )		( 453 )
Other expenses, net	$	( 218 )	$	194	$	( 1,320 )	$	1,003

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15. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At September 30, 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 September 30, 2022
Revenues and other income:
Oil and gas revenue	$	296,980	$	42,473	$	—	$	116,603	$	—	$	—	$	456,056

Other income, net	1		—		—		698		( 82,537 )		81,886		48
Total revenues and other income	296,981		42,473		—		117,301		( 82,537 )		81,886		456,104
Costs and expenses:
Oil and gas production	23,911		11,921		—		26,540		—		—		62,372
Facilities insurance modifications, net	494		—		—		—		—		—		494
Exploration expenses	9,459		1,071		2,182		2,674		1,829		—		17,215
General and administrative	3,967		1,991		2,624		2,804		44,577		( 31,956 )		24,007
Depletion, depreciation and amortization	65,288		7,741		143		32,701		440		—		106,313

Interest and other financing costs, net(1)	16,922		( 595 )		( 18,402 )		2,785		29,086		—		29,796
Derivatives, net	—		—		—		—		( 113,842 )		—		( 113,842 )
Other expenses, net	( 101,457 )		( 6,464 )		145		( 6,317 )		33		113,842		( 218 )
Total costs and expenses	18,584		15,665		( 13,308 )		61,187		( 37,877 )		81,886		126,137
Income (loss) before income taxes	278,397		26,808		13,308		56,114		( 44,660 )		—		329,967
Income tax expense (benefit)	98,413		7,371		—		( 275 )		2,204		—		107,713
Net income (loss)	$	179,984	$	19,437	$	13,308	$	56,389	$	( 46,864 )	$	—	$	222,254

Consolidated capital expenditures, net	$	40,871	$	2,435	$	114,339	$	43,612	$	1,834	$	—	$	203,091

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	Ghana(2)		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico(3)		Corporate & Other		Eliminations		Total
	(In thousands)
Nine months ended September 30, 2022
Revenues and other income:
Oil and gas revenue	$	1,032,551	$	261,442	$	—	$	441,446	$	—	$	—	$	1,735,439
Gain on sale of assets	—		—		—		471		—		—		471
Other income, net	1		—		—		1,726		340,768		( 342,352 )		143
Total revenues and other income	1,032,552		261,442		—		443,643		340,768		( 342,352 )		1,736,053
Costs and expenses:
Oil and gas production	137,030		60,384		—		79,850		—		—		277,264
Facilities insurance modifications, net	7,246		—		—		—		—		—		7,246
Exploration expenses	11,433		4,047		80,271		19,770		3,135		—		118,656
General and administrative	11,379		5,008		6,890		11,181		138,783		( 98,817 )		74,424
Depletion, depreciation and amortization	229,074		40,729		257		115,648		1,253		—		386,961

Interest and other financing costs, net(1)	46,208		( 1,682 )		( 46,903 )		8,244		86,450		—		92,317
Derivatives, net	—		—		—		—		243,534		—		243,534
Other expenses, net	215,340		17,553		( 1,200 )		11,355		( 834 )		( 243,534 )		( 1,320 )
Total costs and expenses	657,710		126,039		39,315		246,048		472,321		( 342,351 )		1,199,082
Income (loss) before income taxes	374,842		135,403		( 39,315 )		197,595		( 131,553 )		( 1 )		536,971
Income tax expense (benefit)	133,193		55,420		—		2,828		4,703		—		196,144
Net income (loss)	$	241,649	$	79,983	$	( 39,315 )	$	194,767	$	( 136,256 )	$	( 1 )	$	340,827

Consolidated capital expenditures, net	$	32,814	$	26,732	$	261,755	$	107,856	$	4,545	$	—	$	433,702

As of September 30, 2022
Property and equipment, net	$	1,627,871	$	385,442	$	1,225,991	$	881,990	$	17,373	$	—	$	4,138,667
Total assets	$	3,211,263	$	1,130,390	$	1,727,997	$	3,649,195	$	18,987,516	$	( 23,784,949 )	$	4,921,412

______________________________________

(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 nine months ended September 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 nine months ended September 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 September 30, 2021
Revenues and other income:
Oil and gas revenue	$	67,247	$	35,063	$	—	$	96,626	$	—	$	—	$	198,936
Gain on sale of assets	—		—		—		—		1,538		—		1,538
Other income, net	—		—		—		256		65,941		( 66,131 )		66
Total revenues and other income	67,247		35,063		—		96,882		67,479		( 66,131 )		200,540
Costs and expenses:
Oil and gas production	10,490		13,029		—		26,797		—		—		50,316
Facilities insurance modifications, net	1,555		—		—		—		( 1 )		—		1,554
Exploration expenses	89		2,089		7,081		13,975		748		—		23,982
General and administrative	3,165		581		2,980		4,177		39,464		( 27,908 )		22,459
Depletion, depreciation and amortization	20,958		5,999		15		37,551		391		—		64,914

Interest and other financing costs, net(1)	16,836		( 446 )		( 11,604 )		3,446		18,641		—		26,873
Derivatives, net	—		—		—		—		38,224		—		38,224
Other expenses, net	34,382		3,229		( 106 )		648		265		( 38,224 )		194
Total costs and expenses	87,475		24,481		( 1,634 )		86,594		97,732		( 66,132 )		228,516
Income (loss) before income taxes	( 20,228 )		10,582		1,634		10,288		( 30,253 )		1		( 27,976 )
Income tax expense (benefit)	( 6,782 )		5,758		—		—		1,645		—		621
Net income (loss)	$	( 13,446 )	$	4,824	$	1,634	$	10,288	$	( 31,898 )	$	1	$	( 28,597 )

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

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	Ghana		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Nine months ended September 30, 2021
Revenues and other income:
Oil and gas revenue	$	313,126	$	147,424	$	—	$	298,905	$	—	$	—	$	759,455
Gain on sale of assets	—		—		—		—		1,564		—		1,564
Other income, net	1		—		—		1,028		347,866		( 348,685 )		210
Total revenues and other income	313,127		147,424		—		299,933		349,430		( 348,685 )		761,229
Costs and expenses:
Oil and gas production	80,189		56,373		—		75,309		—		—		211,871
Facilities insurance modifications, net	3,495		—		—		—		—		—		3,495
Exploration expenses	164		4,666		10,812		20,541		5,269		—		41,452
General and administrative	8,636		2,883		7,677		12,620		129,108		( 94,296 )		66,628
Depletion, depreciation and amortization	132,232		34,474		46		124,598		1,266		—		292,616

Interest and other financing costs, net(1)	36,890		( 1,218 )		( 33,816 )		12,307		78,348		( 1,784 )		90,727
Derivatives, net	—		—		—		—		252,606		—		252,606
Other expenses, net	193,370		34,096		( 2,348 )		26,185		2,306		( 252,606 )		1,003
Total costs and expenses	454,976		131,274		( 17,629 )		271,560		468,903		( 348,686 )		960,398
Income (loss) before income taxes	( 141,849 )		16,150		17,629		28,373		( 119,473 )		1		( 199,169 )
Income tax expense (benefit)	( 48,770 )		19,957		—		—		6,196		—		( 22,617 )
Net income (loss)	$	( 93,079 )	$	( 3,807 )	$	17,629	$	28,373	$	( 125,669 )	$	1	$	( 176,552 )

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

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

______________________________________

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


	Nine Months Ended September 30,
	2022		2021
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	543,349	$	377,850
Acquisition of oil and gas properties	21,205		—
Proceeds on sale of assets	( 118,703 )		( 5,327 )
Adjustments:
Changes in capital accruals	1,511		( 16,523 )
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	35,570		24,680
Capitalized interest	( 57,489 )		( 31,956 )
Other	8,259		4,686
Total consolidated capital expenditures, net	$	433,702	$	353,410

______________________________________

(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 pursue a 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, a 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 third quarter of 2022, Ghana production averaged approximately 111,100 Bopd gross (36,900 Bopd net). Jubilee production averaged approximately 88,900 Bopd gross (32,600 Bopd net) and TEN production averaged approximately 22,200 Bopd gross (4,300 Bopd net).

In the third quarter of 2022, the multi-year development drilling program continued to progress with the completion of one producer well at TEN which was brought online in the third quarter of 2022. 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. In October 2022, a second well targeting a different fairway was drilled. The well encountered approximately 5 meters of net oil pay with poorer than expected reservoir quality and has been plugged and abandoned. The partnership will continue to evaluate the full results of the two wells to high-grade and optimize the future drilling plans for TEN. In October 2022, the rig moved back to Jubilee to commence drilling operations on Jubilee Southeast.

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.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 14,700 Boepd net (~83% oil) for the third 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 Kodiak-3ST well was brought online in early September 2022, with insurance proceeds expected to cover a substantial portion of the costs incurred to return the Kodiak #3 well to production. Well results and initial production were in line with expectations, however well productivity declined through the end of the third quarter of 2022. Workover plans are being developed for remediation.

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. During the third quarter of 2022, the Field Development Plan for the Winterfell field was approved by all partners and a rig has been secured by Beacon, the operator of the Winterfell field, to undertake the development drilling, including the sidetrack and completion of the Winterfell-1 well, completion of the Winterfell-2 well and drilling and completion of the Winterfell-3 well in an adjacent fault block to the southeast of the Winterfell-1 discovery well as part of the Field Development Plan. Host facility production handling agreement and midstream export agreement are expected to be completed within the next several months.

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. Additionally, in September 2022, Kosmos completed the acquisition of an additional 3.2% interest in the Winterfell area in Green Canyon Blocks 943, 944, 987 and 988 and an additional 1.4% interest in Green Canyon blocks 899 and 900 for $6.6 million. As a result of the two transactions, our participating interests in the Green Canyon Blocks 943, 944, 987, and 988 is now 25.0% and our participating interests in the Green Canyon Blocks 899 and 900 is now 37.8%.

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%.

In August 2022, the operator of the Helix Producer I (the “HP-I”) production vessel disconnected the HP-I for a scheduled dry-dock inspection required by the U.S. Coast Guard. As a result, production from the Tornado field was shut-in approximately 45 days while the vessel underwent its scheduled dry-dock. In September 2022, the HP-1 was successfully brought back online and production from the Tornado field re-commenced. Production from the Tornado field was also impacted in late September 2022 and early October 2022 by loop currents in the Gulf of Mexico.

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In September 2022, the operator of the Delta House floating production facility shut in production as the export pipeline underwent scheduled maintenance. As a result, production from the Odd Job, Marmalard, SOB II and Nearly Headless Nick fields were shut-in approximately 27 days. In late October 2022, the Delta House production facility saw approximately two weeks of additional unplanned downtime due to an issue with the gas compressors.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 29,700 Bopd gross (9,300 Bopd net) in the third quarter of 2022.

In August 2022, the partnership entered into a rig contract for the next drilling campaign, which is expected to begin in the second half of 2023.

In October 2022, we entered into a farm-out agreement with Panoro Energy ASA (Panoro) to farm-out a 6.0% participating interest in Block S offshore Equatorial Guinea, resulting in our participating interest in Block S reducing to 34.0%. The transaction is expected to close around the end of the year.

Mauritania and Senegal

In June 2022, the exploration period of Block C8 offshore Mauritania expired. In October 2022, the partnership and the government of Mauritania executed a new Production Sharing Contract (“PSC”) covering the BirAllah and Orca discoveries. The new PSC, which has been approved by the government of Mauritania and will become effective upon being published in Mauritania’s Official Gazette, provides up to thirty months 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 enhanced back-in rights for the Government of Mauritania, local content, SMH’s capacity building and an environmental fund. Kosmos’ participating interest in the new PSC will be 28.0% and full election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%.

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 third quarter of 2022 and post quarter-end:

• FLNG: on track for sailaway in first half of 2023 as construction and mechanical completion activities continue and commissioning work has begun

• FPSO: In September 2022, Typhoon Muifa passed through the COSCO shipyard in Qidong in China causing the mooring lines of the Greater Tortue FPSO to become compromised. As a result, the Greater Tortue FPSO drifted approximately 200 meters off the quayside. The Greater Tortue FPSO has been returned to the quayside of the COSCO shipyard in China and inspections conducted to date have not identified any significant damage. The forward plan is to complete all inspections and incorporate any findings into mechanical completion activities along with commissioning work prior to sailaway, which is expected around year-end.

• Hub Terminal: largely complete with the living quarters platform installed and commissioning activities commenced

• Subsea: shallow water gas export pipeline from the FPSO to the hub terminal has been installed and deepwater pipelay vessel is in the region conducting final testing prior to mobilization which is expected in the coming weeks to lay the deepwater pipeline and in-field flowlines

• Drilling: successfully drilled all four wells with expected production capacity significantly more than required at first gas

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Results of Operations

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	4,458		2,719		16,028		11,349
Gas (MMcf)	859		1,078		3,115		3,624
NGL (MBbl)	84		111		330		365
Total (MBoe)	4,685		3,010		16,877		12,318
Total (Boepd)	50,926		32,714		61,821		45,121

Revenues:
Oil sales	$	444,491	$	190,599	$	1,699,167	$	737,381
Gas sales	8,595		4,508		23,802		12,727
NGL sales	2,970		3,829		12,470		9,347
Total oil and gas revenue	$	456,056	$	198,936	$	1,735,439	$	759,455

Average oil sales price per Bbl	$	99.71	$	70.10	$	106.01	$	64.97
Average gas sales price per Mcf	10.01		4.18		7.64		3.51
Average NGL sales price per Bbl	35.36		34.50		37.79		25.61
Average total sales price per Boe	97.34		66.10		102.83		61.65

Costs:
Oil and gas production, excluding workovers	$	58,811	$	47,182	$	268,154	$	201,975
Oil and gas production, workovers	3,561		3,134		9,110		9,896
Total oil and gas production costs	$	62,372	$	50,316	$	277,264	$	211,871

Depletion, depreciation and amortization	$	106,313	$	64,914	$	386,961	$	292,616

Average cost per Boe:
Oil and gas production, excluding workovers	$	12.55	$	15.68	$	15.89	$	16.40
Oil and gas production, workovers	0.76		1.04		0.54		0.80
Total oil and gas production costs	13.31		16.72		16.43		17.20

Depletion, depreciation and amortization	22.69		21.57		22.93		23.76
Total	$	36.00	$	38.29	$	39.36	$	40.96

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The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of September 30, 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	0.50	—	—

Mauritania / Senegal

Greater Tortue Ahmeyim Unit	—	—	1	0.27	—	—	3	0.80
Senegal Cayar Profond	—	—	—	—	3	0.90	—	—
Total	1	0.20	1	0.27	6	1.80	18	5.36

(1) Includes the NT-11 well which is considered a step out well from an accounting perspective, but is being 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 September 30, 2022 compared to three months ended September 30, 2021


	Three Months Ended
	September 30,				Increase
	2022		2021		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	456,056	$	198,936	$	257,120
Gain on sale of assets	—		1,538		(1,538)
Other income, net	48		66		(18)
Total revenues and other income	456,104		200,540		255,564
Costs and expenses:
Oil and gas production	62,372		50,316		12,056
Facilities insurance modifications, net	494		1,554		(1,060)
Exploration expenses	17,215		23,982		(6,767)
General and administrative	24,007		22,459		1,548
Depletion, depreciation and amortization	106,313		64,914		41,399

Interest and other financing costs, net	29,796		26,873		2,923
Derivatives, net	(113,842)		38,224		(152,066)
Other expenses, net	(218)		194		(412)
Total costs and expenses	126,137		228,516		(102,379)
Income (loss) before income taxes	329,967		(27,976)		357,943
Income tax expense	107,713		621		107,092
Net income (loss)	$	222,254	$	(28,597)	$	250,851

Oil and gas revenue. Oil and gas revenue increased by $257.1 million during the three months ended September 30, 2022, as compared to the three months ended September 30, 2021 primarily as a result of higher production rates at Jubilee and our acquisition of additional interests in Ghana during the fourth quarter of 2021 which drove increased sales volumes in Ghana as well as higher average oil prices. We sold 4,685 MBoe at an average realized price per barrel equivalent of $97.34 during the three months ended September 30, 2022 and 3,010 MBoe at an average realized price per barrel equivalent of $66.10 during the three months ended September 30, 2021.

Oil and gas production. Oil and gas production costs increased by $12.1 million during the three months ended September 30, 2022, as compared to the three months ended September 30, 2021 primarily as a result of increased sales volumes in Ghana, partially offset by lower production costs per barrel driven by field production mix in our Ghana business unit.

Exploration expenses. Exploration expenses decreased by $6.8 million during the three months ended September 30, 2022, as compared to the three months ended September 30, 2021 primarily as result of approximately $9.3 million of exploration expenses for the three months ended September 30, 2022 related to the two abandoned Ntomme step out wells, compared to approximately $7.0 million related to the exit of an exploration lease in Mauritania and the Zora exploration well which did not find hydrocarbons and was plugged and abandoned in August 2021 with $12.6 million of well costs charged to exploration expense for the three months ended September 30, 2021.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $41.4 million during the three months ended September 30, 2022, as compared with the three months ended September 30, 2021 primarily as a result of higher sales volumes during the quarter.

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Interest and other financing costs, net. Interest and other financing costs, net increased $2.9 million during the three months ended September 30, 2022, as compared with the three months ended September 30, 2021 primarily as a result of increased interest expense on the 7.750% Senior Notes issued in October 2021 and guarantee fees on the Tortue FPSO transaction, offset by increased capitalized interest related to the Greater Tortue Ahmeyim project.

Derivatives, net. During the three months ended September 30, 2022 and 2021, we recorded a gain of $113.8 million and a loss of $38.2 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.

Income tax expense (benefit). For the three months ended September 30, 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.

Nine months ended September 30, 2022 compared to nine months ended September 30, 2021



	Nine Months Ended
	September 30,				Increase
	2022		2021		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	1,735,439	$	759,455	$	975,984
Gain on sale of assets	471		1,564		(1,093)
Other income, net	143		210		(67)
Total revenues and other income	1,736,053		761,229		974,824
Costs and expenses:
Oil and gas production	277,264		211,871		65,393
Facilities insurance modifications, net	7,246		3,495		3,751
Exploration expenses	118,656		41,452		77,204
General and administrative	74,424		66,628		7,796
Depletion, depreciation and amortization	386,961		292,616		94,345

Interest and other financing costs, net	92,317		90,727		1,590
Derivatives, net	243,534		252,606		(9,072)
Other expenses, net	(1,320)		1,003		(2,323)
Total costs and expenses	1,199,082		960,398		238,684
Income (loss) before income taxes	536,971		(199,169)		736,140
Income tax expense	196,144		(22,617)		218,761
Net income (loss)	$	340,827	$	(176,552)	$	517,379

Oil and gas revenue. Oil and gas revenue increased by $976.0 million during the nine months ended September 30, 2022, as compared to the nine months ended September 30, 2021 primarily as a result of higher production rates at Jubilee and our acquisition of additional interests in Ghana during the fourth quarter of 2021 which drove increased sales volumes in Ghana as well as higher average oil prices. We sold 16,877 MBoe at an average realized price per barrel equivalent of $102.83 during the nine months ended September 30, 2022 and 12,318 MBoe at an average realized price per barrel equivalent of $61.65 during the nine months ended September 30, 2021.

Oil and gas production. Oil and gas production costs increased by $65.4 million during the nine months ended September 30, 2022, as compared to the nine months ended September 30, 2021 primarily as a result of increased sales volumes in Ghana and by field production mix in our Ghana business unit.

Exploration expenses. Exploration expenses increased by $77.2 million during the nine months ended September 30, 2022, as compared to the nine months ended September 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

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written off to exploration expense with the expiration of the exploration period of Block C8, approximately $10.9 million related to the two abandoned Ntomme step out wells, and approximately $15.0 million related to the exit of leases in the U.S. Gulf of Mexico and Mauritania business units, compared to the Zora exploration well, which did not find hydrocarbons and was plugged and abandoned in August 2021 with $14.1 million of well costs charged to exploration expense for the nine months ended September 30, 2021.

General and administrative. General and administrative costs increased by $7.8 million during the nine months ended September 30, 2022, as compared with the nine months ended September 30, 2021 primarily as a result of increased compensation and benefits, travel costs and professional fees for the nine months ended September 30, 2022.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $94.3 million during the nine months ended September 30, 2022, as compared with the nine months ended September 30, 2021 primarily as a result of higher sales volumes in the current year.

Interest and other financing costs, net. Interest and other financing costs, net increased $1.6 million during the nine months ended September 30, 2022, as compared to the nine months ended September 30, 2021, primarily as a result of increased interest expense on the 7.750% Senior Notes and the 7.500% Senior Notes issued during 2021 and guarantee fees on the Greater Tortue FPSO transaction, offset by $15.2 million for loss on extinguishment of debt during the second quarter of 2021 related to the Facility amendment and increased capitalized interest related to the Greater Tortue Ahmeyim project.

Derivatives, net. During the nine months ended September 30, 2022 and 2021, we recorded a loss of $243.5 million and a loss of $252.6 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 nine months ended September 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.

Oil prices are historically 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 nine months ended September 30, 2022 and 2021:


	Nine Months Ended
	September 30,
	2022		2021
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	863,236	$	143,841
Net proceeds from issuance of senior notes	—		444,375
Borrowings under long-term debt	—		250,000
Proceeds on sale of assets	118,703		5,327
	981,939		843,543
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	543,349		377,850
Acquisition of oil and gas properties	21,205		—
Notes receivable from partners	28,188		41,712
Payments on long-term debt	322,500		400,000
Purchase of treasury stock	2,753		1,100
Dividends	655		512
Deferred financing costs	6,288		17,291
	924,938		838,465
Increase in cash, cash equivalents and restricted cash	$	57,001	$	5,078

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2022 was $863.2 million compared with net cash provided by operating activities for the nine months ended September 30, 2021 of $143.8 million. The increase in cash provided by operating activities in the nine months ended September 30, 2022 when compared to the same period in 2021 is primarily a result of increased sales volumes and higher oil prices.

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


	September 30, 2022
	(In thousands)
Cash and cash equivalents	$	231,565
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	152,500
Net debt	$	2,120,603

Availability under the Facility	$	550,000
Availability under the Corporate Revolver	$	250,000
Available borrowings plus cash and cash equivalents	$	1,031,565

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 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 $125 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

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• Approximately $325 million related to development of Phase 1 of Greater Tortue Ahmeyim, net of the Greater Tortue FPSO transaction benefit

• Approximately $25 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 September 30, 2022, we have spent approximately $508.0 million on capital expenditures, excluding the offsetting impact of the Tullow and Kodiak pre-emption transactions and Winterfell acquisitions.

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 nine months ended September 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 October 2022, during the Fall 2022 redetermination, the Company’s lending syndicate approved a borrowing base of approximately $1.24 billion. As of September 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 September 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 September 30, 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.

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• 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 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 September 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.

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

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

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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.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 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,																				September 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	$	534,034
7.750% Senior Notes	—			—			—			—			—			400,000			$	400,000	$	320,992
7.500% Senior Notes	—			—			—			—			—			450,000			450,000		352,598

Variable rate debt:
Weighted average interest rate	7.76		%	8.45		%	8.39		%	8.06		%	8.29		%	8.53		%
Facility(1)	$	—		$	—		$	—		$	169,011		$	352,418		$	178,571		$	700,000	$	700,000

GoM Term Loan	7,500			30,000			30,000			85,000			—			—			152,500		152,500

Total principal debt repayments(1)	$	7,500		$	30,000		$	30,000		$	254,011		$	1,002,418		$	1,028,571		$	2,352,500
Interest & commitment fee payments on long-term debt	35,318			193,773			188,803			168,369			117,837			69,931			774,031
Operating leases(4)	989			4,003			4,074			4,145			4,216			10,825			28,252
Purchase obligations(5)	2,880			68,198			34,976			—			—			—			106,054

__________________________________

(1) The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of September 30, 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 October 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, but not limited to, 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 nine months ended September 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	(257,112)
Contract maturities	304,328
Fair value of contracts outstanding as of September 30, 2022	$	(19,099)

Commodity Price Risk

The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Substantially all of our oil sales are indexed against Dated Brent, and Heavy Louisiana Sweet. Oil prices in the first nine months of 2022 ranged between $78.99 and $137.64 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first nine 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 September 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						September 30,
Term	Type of Contract	Index	MBbl	(Receivable)		Put		Floor		Ceiling		2022(2)
												(In thousands)
2022:
Oct — Dec	Three-way collars	Dated Brent	1,125	$	0.64	$	43.33	$	56.67	$	76.91	$	(12,025)
Oct — Dec	Three-way collars	NYMEX WTI	250	1.45		50.00		65.00		85.00		(809)
Oct — Dec	Two-way collars	Dated Brent	1,500	1.22		—		62.50		83.33		(10,850)
Oct — Dec	Sold calls(1)	Dated Brent	395	—		—		—		60.00		(9,707)
2023:
Jan — Dec	Three-way collars	Dated Brent	4,000	1.21		48.75		70.00		106.38		758
Jan — Dec	Two-way collars	Dated Brent	2,000	2.50		—		75.00		125.00		13,534

__________________________________

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

(2) Fair values are based on the average forward oil prices on September 30, 2022.

In October 2022, we entered into Dated Brent three-way collar contracts for 1.0 MMBbl from January 2023 through December 2023 with a sold put price of $50.00 per barrel, a floor price of $75.00 per barrel and a ceiling price of $110.00 per barrel. In addition, we entered into Dated Brent two-way collar contracts for 2.0 MMBbl from January 2023 through December 2023 with a floor price of $70.00 per barrel and a ceiling price of $110.00 per barrel.

At September 30, 2022, our open commodity derivative instruments were in a net liability position of $19.1 million. As of September 30, 2022, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $43.0 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $39.0 million.

Interest Rate Sensitivity

Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Facility and GoM Term Loan, which as of September 30, 2022 total $0.9 billion and have a weighted average interest rate of 6.8%, 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 $3.1 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

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As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 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.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		Kosmos Energy Ltd.
		(Registrant)

Date	November 7, 2022	/s/ NEAL D. SHAH
		Neal D. Shah
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer)

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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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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TABLE OF CONTENTS

Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Qualitative and Quantitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

Exhibits

31.1 Certification of Chief Executive Officer Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Chief Executive Officer Pursuant to Section906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Chief Financial Officer Pursuant to Section906 of the Sarbanes-Oxley Act of 2002.

KOS 10-Q Quarter ended Sept. 30, 2022

Exhibits