KOS 10-Q Quarterly Report Sept. 30, 2023

KOSMOS ENERGY LTD.

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kos-20230930

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, 2023


☐			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 2, 2023
Common Shares, $0.01 par value						460,129,711

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			29
Item 3. Quantitative and Qualitative Disclosures about Market Risk			43
Item 4. Controls and Procedures			44

PART II. OTHER INFORMATION

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

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 (as amended or as amended and restated from time to time).
“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, however, forecasted capital expenditures in relation to the additional interests in Ghana acquired in the October 2021 acquisition of Anadarko WCTP are not included, to (y) the aggregate loan amounts outstanding under the Facility.
“LIBOR”						London Interbank Offered Rate
“LSE”						London Stock Exchange.
“LTIP”						Long Term Incentive Plan.

Table of Contents


“MBbl”						Thousand barrels of oil.
“MBoe”						Thousand barrels of oil equivalent.
“Mcf”						Thousand cubic feet of natural gas.
“Mcfpd”						Thousand cubic feet per day of natural gas.
“MMBbl”						Million barrels of oil.
“MMBoe”						Million barrels of oil equivalent.
“MMBtu”						Million British thermal units.
“MMcf”						Million cubic feet of natural gas.
“MMcfd”						Million cubic feet per day of natural gas.
“MMTPA”						Million metric tonnes per annum.
“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.
“Net debt”						Total long-term debt less cash and cash equivalents and total restricted cash.
“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.
“SOFR”						Secured Overnight Financing Rate
“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.

Table of Contents


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

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KOSMOS ENERGY LTD.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	September 30, 2023		December 31, 2022
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	138,742	$	183,405

Receivables
Joint interest billings, net	29,851		28,851
Oil sales	71,700		67,483

Other	17,016		23,401
Inventories	155,011		133,515
Prepaid expenses and other	49,476		24,722
Derivatives	—		7,344
Total current assets	461,796		468,721
Property and equipment:
Oil and gas properties, net	4,174,239		3,837,437
Other property, net	5,730		5,210
Property and equipment, net	4,179,969		3,842,647
Other assets:

Restricted cash	3,416		3,416
Long-term receivables	297,327		235,696
Deferred financing costs, net of accumulated amortization of $ 15,003 and $ 13,263 at September 30, 2023 and December 31, 2022, respectively	2,900		4,640
Deferred tax assets	2,664		—
Derivatives	698		1,725
Other	20,631		23,143
Total assets	$	4,969,401	$	4,579,988
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	199,031	$	212,275
Accrued liabilities	338,790		325,206
Current maturities of long-term debt	—		30,000
Derivatives	26,597		6,773
Total current liabilities	564,418		574,254
Long-term liabilities:
Long-term debt, net	2,389,197		2,195,911
Derivatives	2,402		778
Asset retirement obligations	330,102		300,800
Deferred tax liabilities	433,628		468,445
Other long-term liabilities	249,985		251,952
Total long-term liabilities	3,405,314		3,217,886
Stockholders’ equity:
Preference shares, $ 0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2023 and December 31, 2022	—		—
Common stock, $ 0.01 par value; 2,000,000,000 authorized shares; 504,372,666 and 500,161,421 issued at September 30, 2023 and December 31, 2022, respectively	5,044		5,002
Additional paid-in capital	2,525,634		2,505,694
Accumulated deficit	( 1,294,002 )		( 1,485,841 )
Treasury stock, at cost, 44,263,269 shares at September 30, 2023 and December 31, 2022, respectively	( 237,007 )		( 237,007 )
Total stockholders’ equity	999,669		787,848
Total liabilities and stockholders’ equity	$	4,969,401	$	4,579,988

See accompanying notes.

Table of Contents

KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Revenues and other income:
Oil and gas revenue	$	526,348	$	456,056	$	1,193,843	$	1,735,439
Gain on sale of assets	—		—		—		471
Other income, net	198		48		( 115 )		143
Total revenues and other income	526,546		456,104		1,193,728		1,736,053
Costs and expenses:
Oil and gas production	138,782		62,372		286,297		277,264
Facilities insurance modifications, net	—		494		—		7,246
Exploration expenses	10,290		17,215		33,305		118,656
General and administrative	25,120		24,007		77,731		74,424
Depletion, depreciation and amortization	132,347		106,313		331,634		386,961

Interest and other financing costs, net	25,440		29,796		74,379		92,317
Derivatives, net	45,971		( 113,842 )		42,162		243,534
Other expenses, net	11,055		( 218 )		17,864		( 1,320 )
Total costs and expenses	389,005		126,137		863,372		1,199,082
Income before income taxes	137,541		329,967		330,356		536,971
Income tax expense	52,356		107,713		138,517		196,144
Net income	$	85,185	$	222,254	$	191,839	$	340,827

Net income per share:
Basic	$	0.19	$	0.49	$	0.42	$	0.75
Diluted	$	0.18	$	0.47	$	0.40	$	0.72

Weighted average number of shares used to compute net income per share:
Basic	460,108		455,840		459,477		455,158
Diluted	481,099		476,431		479,738		474,820

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
2023:
Balance as of December 31, 2022	500,161	$	5,002	$	2,505,694	$	( 1,485,841 )	$	( 237,007 )	$	787,848

Equity-based compensation	—	—		10,093		—		—		10,093
Restricted stock units	3,691	37		( 37 )		—		—		—
Tax withholdings on restricted stock units	—	—		( 11,810 )		—		—		( 11,810 )
Net income	—	—		—		83,309		—		83,309
Balance as of March 31, 2023	503,852	5,039		2,503,940		( 1,402,532 )		( 237,007 )		869,440
Dividends	—	—		( 1 )		—		—		( 1 )
Equity-based compensation	—	—		11,121		—		—		11,121
Restricted stock units	493	4		( 4 )		—		—		—
Tax withholdings on restricted stock units	—	—		( 1 )		—		—		( 1 )
Net income	—	—		—		23,345		—		23,345
Balance as of June 30, 2023	504,345	5,043		2,515,055		( 1,379,187 )		( 237,007 )		903,904
Dividends	—	—		—		—		—		—
Equity-based compensation	—	—		10,580		—		—		10,580
Restricted stock units	28	1		( 1 )		—		—		—

Net income	—	—		—		85,185		—		85,185
Balance as of September 30, 2023	504,373	$	5,044	$	2,525,634	$	( 1,294,002 )	$	( 237,007 )	$	999,669

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 awards and units	487	5		( 5 )		—		—		—

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

Equity-based compensation	—	—		8,871		—		—		8,871
Restricted stock units	89	1		( 1 )		—		—		—

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

See accompanying notes.

Table of Contents

KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2023		2022
Operating activities
Net income	$	191,839	$	340,827
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	339,177		394,799
Deferred income taxes	( 37,481 )		( 37,445 )
Unsuccessful well costs and leasehold impairments	2,244		83,086

Change in fair value of derivatives	52,467		257,112
Cash settlements on derivatives, net (including $( 12.3 ) million and $( 289.9 ) million on commodity hedges during 2023 and 2022)	( 21,478 )		( 304,328 )
Equity-based compensation	31,778		25,896
Gain on sale of assets	—		( 471 )
Loss on extinguishment of debt	1,503		192
Other	2,547		( 5,940 )
Changes in assets and liabilities:
(Increase) decrease in receivables	( 5,766 )		54,035
(Increase) in inventories	( 26,847 )		( 4,377 )
(Increase) in prepaid expenses and other	( 22,920 )		( 5,704 )
Increase (decrease) in accounts payable	( 13,244 )		64,216
Increase (decrease) in accrued liabilities	( 22,425 )		1,338
Net cash provided by operating activities	471,394		863,236
Investing activities
Oil and gas assets	( 611,914 )		( 543,349 )
Acquisition of oil and gas properties	—		( 21,205 )
Proceeds on sale of assets	—		118,703
Notes receivable from partners	( 46,632 )		( 28,188 )
Net cash used in investing activities	( 658,546 )		( 474,039 )
Financing activities
Borrowings under long-term debt	300,000		—
Payments on long-term debt	( 145,000 )		( 322,500 )

Tax withholdings on restricted stock units	( 11,811 )		( 2,753 )
Dividends	( 166 )		( 655 )
Other	( 534 )		( 6,288 )
Net cash provided by (used in) financing activities	142,489		( 332,196 )
Net increase (decrease) in cash, cash equivalents and restricted cash	( 44,663 )		57,001
Cash, cash equivalents and restricted cash at beginning of period	186,821		174,896
Cash, cash equivalents and restricted cash at end of period	$	142,158	$	231,897

Supplemental cash flow information
Cash paid for:
Interest, net of capitalized interest	$	50,814	$	79,787
Income taxes, net of refund received	$	212,352	$	195,782

See accompanying notes.

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KOSMOS ENERGY LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Kosmos Energy Ltd. is incorporated in the State of Delaware 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 offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea 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, 2022, 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, current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows.

Cash, Cash Equivalents and Restricted Cash


	September 30, 2023		December 31, 2022
	(In thousands)
Cash and cash equivalents	$	138,742	$	183,405

Restricted cash - long-term	3,416		3,416
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	142,158	$	186,821

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.

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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.

Inventories

Inventories consisted of $ 141.5 million and $ 125.3 million of materials and supplies and $ 13.5 million and $ 8.2 million of hydrocarbons as of September 30, 2023 and December 31, 2022, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value.

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

Revenue Recognition

Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a 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 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 of or month after the sale.

Oil and gas revenue is composed of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(In thousands)
Revenues from contract with customers - Equatorial Guinea	$	74,998	$	41,178	$	182,738	$	263,532
Revenues from contract with customers - Ghana	355,098		301,855		735,675		1,044,039
Revenues from contract with customers - U.S. Gulf of Mexico	102,968		116,603		285,735		441,446
Provisional oil sales contracts	( 6,716 )		( 3,580 )		( 10,305 )		( 13,578 )
Oil and gas revenue	$	526,348	$	456,056	$	1,193,843	$	1,735,439

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 readily available, we believe that the loss of our purchasers and/or marketing agents would not have a long‑term material adverse effect on our financial position or results of operations.

3. Acquisitions and Divestitures

In February 2023, Kosmos and Panoro Energy ASA (“Panoro”) entered into a petroleum contract covering Block EG-01 offshore Equatorial Guinea with the Republic of Equatorial Guinea. Kosmos holds a 24 % participating interest in the block and the operator, Panoro, holds a 56 % participating interest. The Equatorial Guinean national oil company, Guinea Equatorial De Petroles (“GEPetrol”), currently has a 20 % carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol’s 20 % carried interest will convert to a 20 % participating interest. Block EG-01 currently comprises approximately 59,400 acres ( 240 square kilometers), with a first exploration period of three years from the effective date (March 1, 2023).

In March 2023, we closed a farm-out agreement with Panoro, whereby Panoro acquired a 6.0 % participating interest in Block S offshore Equatorial Guinea. As a result of the farm-out agreement, Kosmos’ participating interest in Block S was reduced to 34.0 %.

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4. Long-term 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. The amount financed by Kosmos is to be repaid with interest through the national oil companies’ share of future revenues. As of September 30, 2023 and December 31, 2022, the balance due from the national oil companies was $ 243.6 million and $ 196.9 million, respectively, which is classified as Long-term receivables on our consolidated balance sheets. As of September 30, 2023 and December 31, 2022, accrued interest on the balance due from the national oil companies was $ 32.7 million and $ 21.5 million, respectively. Interest income on the long-term notes receivable was $ 4.0 million and $ 2.5 million for the three months ended September 30, 2023 and 2022, respectively, and $ 11.3 million and $ 6.8 million for the nine months ended September 30, 2023 and 2022, respectively.

5. Property and Equipment

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


	September 30, 2023		December 31, 2022
	(In thousands)
Oil and gas properties:
Proved properties	$	7,535,104	$	6,953,435
Unproved properties	403,481		341,334
Total oil and gas properties	7,938,585		7,294,769
Accumulated depletion	( 3,764,346 )		( 3,457,332 )
Oil and gas properties, net	4,174,239		3,837,437

Other property	64,268		60,730
Accumulated depreciation	( 58,538 )		( 55,520 )
Other property, net	5,730		5,210

Property and equipment, net	$	4,179,969	$	3,842,647

We recorded depletion expense of $ 123.5 million and $ 100.0 million for the three months ended September 30, 2023 and 2022, respectively, and $ 307.0 million and $ 366.4 million for the nine months ended September 30, 2023 and 2022, respectively.

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, 2023.


	September 30, 2023
	(In thousands)
Beginning balance	$	145,957
Additions to capitalized exploratory well costs pending the determination of proved reserves	8,487
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	—
Ending balance	$	154,444

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


	September 30, 2023		December 31, 2022
	(In thousands, except project counts)
Exploratory well costs capitalized for a period of one year or less	$	—	$	—
Exploratory well costs capitalized for a period of one to three years	34,028		32,770
Exploratory well costs capitalized for a period of four to seven years	120,416		113,187
Ending balance	$	154,444	$	145,957
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	2		2

As of September 30, 2023, 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 and the Asam discovery in Block S offshore Equatorial Guinea.

Yakaar and Teranga Discoveries — In May 2016, we drilled the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal, which encountered hydrocarbon pay. In June 2017, we drilled 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 drilled 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 July 2024. The Yakaar and Teranga discoveries are being analyzed as a joint development. During 2023 we have continued progressing appraisal studies and maturing concept design. Following additional evaluation, a final investment decision for the development of the project is expected to be made.

Asam Discovery — In October 2019, we drilled the S-5 exploration well offshore Equatorial Guinea, which encountered hydrocarbon pay. The discovery was subsequently named Asam. In July 2020, an appraisal work program was approved by the government of Equatorial Guinea. The well is located within tieback range of the Ceiba FPSO and the appraisal work program is currently ongoing to integrate all available data into models to establish the scale of the discovered resource and evaluate the optimum development solution. During the fourth quarter of 2022, we received approval from the Government of Equatorial Guinea to enter the second sub-period phase of the Block S exploration license with a scheduled expiration in December 2024. Additionally, in December 2022 the Asam Field appraisal report was submitted to the Government of Equatorial Guinea. During 2023, studies and concept design continued to progress. Following additional evaluation, a decision regarding commerciality is expected to be made.

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7. Debt


	September 30, 2023		December 31, 2022
	(In thousands)
Outstanding debt principal balances:
Facility	$	925,000	$	625,000

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	—		145,000
Total long-term debt	2,425,000		2,270,000
Unamortized deferred financing costs and discounts	( 35,803 )		( 44,089 )
Total debt, net	2,389,197		2,225,911
Less: Current maturities of long-term debt	—		( 30,000 )
Long-term debt, net	$	2,389,197	$	2,195,911

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of September 30, 2023, borrowings under the Facility totaled $ 925.0 million and the undrawn availability under the Facility was $ 220.1 million. Final maturity of the Facility is in March 2027. In October 2023, during the Fall 2023 redetermination, the Company’s lending syndicate approved a borrowing base capacity of $ 1.25 billion increasing the undrawn availability by approximately $ 104.9 million. 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 and Equatorial Guinea.

On November 23, 2022, the Company amended the Facility to update the interest rate benchmark from LIBOR to term SOFR, effective as of April 19, 2023. As amended, interest on the Facility is the aggregate of the applicable margin ( 3.75 % to 5.00 %, depending on the length of time that has passed from the date the Facility was entered into), plus the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published and a credit adjustment spread. Interest is payable on the last day of each interest period (and, if the interest period is longer than six months , on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 30 % per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20 % per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835 — Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility.

On September 29, 2023, the Company amended the Facility to accede Kosmos Energy Ghana Investments and Kosmos Energy Ghana Holdings Limited, to the Facility as obligors. As a result, the additional interests in Jubilee and TEN that were acquired in the October 2021 acquisition of Anadarko WCTP are now included when calculating the borrowing base amount for the Facility, effective as of October 1, 2023.

On October 19, 2023, the Company amended the Facility to modify the amortization schedule in order to reduce the number of repayment installments from seven to six equal installments, with the first repayment installment scheduled on October 1, 2024, rather than March 31, 2024. There was no change to the final maturity date or final repayment date.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2023 (the most recent assessment date). The Facility, as amended, contains customary cross default provisions.

Corporate Revolver

The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of September 30, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $ 250.0 million with an expiration date of December 31, 2024.

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The Company capitalized $ 6.1 million of deferred financing costs associated with entering into the new revolving credit facility in March 2022, which is being amortized over the term of the new revolving credit facility. On November 23, 2022, the Company amended the Corporate Revolver to update the interest rate benchmark from compounded SOFR to term SOFR, effective as of April 19, 2023. As amended, interest on the Corporate Revolver is the aggregate of a 7.0 % margin, the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published and a credit adjustment spread. Interest is payable on the last day of each interest period (and, if the interest period is longer than six months, on the dates falling at six-month intervals after the first day of the interest period). We pay commitment fees on the undrawn portion of the total commitments. Commitment fees for the lenders are equal to 30 % per annum of the respective margin when a commitment is available for utilization.

We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2023 (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.

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). 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.

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). The 7.750 % Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP acquisition, and on a subordinated, unsecured basis by 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.

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). 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.

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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. On September 15, 2023, the Company repaid the remaining outstanding principal amount of $ 137.5 million plus accrued interest using cash on hand, constituting payment in full. The GoM Term Loan was subsequently terminated pursuant to, and subject to the terms of, the GoM Term Loan.

Principal Debt Repayments

At September 30, 2023, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:


	Payments Due by Year
	Total		2023(2)		2024		2025		2026		2027		Thereafter
	(In thousands)
Principal debt repayments(1)	$	2,425,000	$	—	$	243,047	$	227,450	$	929,282	$	575,221	$	450,000

__________________________________

(1) Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as of September 30, 2023 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. In October 2023, the Company’s lending syndicate approved a borrowing base capacity of $ 1.25 billion and the Company amended the Facility to modify the amortization schedule with the first repayment installment scheduled on October 1, 2024, rather than March 31, 2024.

(2) Represents payments for the period October 1, 2023 through December 31, 2023.

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,
	2023		2022		2023		2022
	(In thousands)
Interest expense	$	54,643	$	45,448	$	155,123	$	131,626
Amortization—deferred financing costs	2,462		2,577		7,543		7,838
Loss on extinguishment of debt	1,503		—		1,503		192
Capitalized interest	( 36,029 )		( 22,163 )		( 99,920 )		( 57,489 )
Deferred interest	( 488 )		4		( 135 )		( 1,436 )
Interest income	( 4,793 )		( 2,956 )		( 13,379 )		( 7,840 )
Other, net	8,142		6,886		23,644		19,426
Interest and other financing costs, net	$	25,440	$	29,796	$	74,379	$	92,317

Capitalized interest for the nine months ended September 30, 2023 and 2022 primarily relates to spend on the Greater Tortue Ahmeyim Phase 1 project. Once development is complete on the Greater Tortue Ahmeyim Phase 1 project, we will no longer capitalize interest on the project.

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.

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Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of September 30, 2023. 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
2023:
Oct - Dec	Three-way collars	Dated Brent	1,500	$	1.34	$	49.17	$	71.67	$	107.58
Oct - Dec	Two-way collars	Dated Brent	1,250	1.69		—		72.00		112.00


2024:
Jan - Dec	Three-way collars	Dated Brent	4,000	1.31		45.00		70.00		96.25
Jan - Jun	Two-way collars	Dated Brent	2,000	1.24		—		65.00		85.00
Jan - Dec	Two-way collars	Dated Brent	2,000	0.46		—		70.00		100.00

__________________________________

The following tables disclose the Company’s derivative instruments as of September 30, 2023 and December 31, 2022, and gain/(loss) from derivatives during the three and nine months ended September 30, 2023 and 2022, respectively:


		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2023		December 31, 2022
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity	Derivatives assets—current	$	—	$	7,344
Provisional oil sales	Receivables: Oil sales	—		1,170
Commodity	Derivatives assets—long-term	698		1,725
Derivative liabilities:
Commodity	Derivatives liabilities—current	( 26,597 )		( 6,773 )
Commodity	Derivatives liabilities—long-term	( 2,402 )		( 778 )
Total derivatives not designated as hedging instruments		$	( 28,301 )	$	2,688


		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)	2023		2022		2023		2022
		(In thousands)
Derivatives not designated as hedging instruments:
Provisional oil sales	Oil and gas revenue	$	( 6,716 )	$	( 3,580 )	$	( 10,305 )	$	( 13,578 )
Commodity	Derivatives, net	( 45,971 )		113,842		( 42,162 )		( 243,534 )
Total derivatives not designated as hedging instruments		$	( 52,687 )	$	110,262	$	( 52,467 )	$	( 257,112 )

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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, 2023 and December 31, 2022, 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.

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2023 and December 31, 2022, 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, 2023
Assets:
Commodity derivatives	$	—	$	698	$	—	$	698
Provisional oil sales	—		—		—		—

Liabilities:
Commodity derivatives	—		( 28,999 )		—		( 28,999 )

Total	$	—	$	( 28,301 )	$	—	$	( 28,301 )
December 31, 2022
Assets:
Commodity derivatives	$	—	$	9,069	$	—	$	9,069
Provisional oil sales	—		1,170		—		1,170

Liabilities:
Commodity derivatives	—		( 7,551 )		—		( 7,551 )

Total	$	—	$	2,688	$	—	$	2,688

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.

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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.

Debt

The following table presents the carrying values and fair values at September 30, 2023 and December 31, 2022:


	September 30, 2023				December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
7.125 % Senior Notes	$	646,600	$	613,444	$	645,699	$	558,201
7.750 % Senior Notes	396,505		370,044		395,893		335,592
7.500 % Senior Notes	446,104		403,574		445,564		361,958
GoM Term Loan	—		—		145,000		145,000

Facility	925,000		925,000		625,000		625,000
Total	$	2,414,209	$	2,312,062	$	2,257,156	$	2,025,751

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, 2023 and 2022, the Company did no t recognize impairment of proved oil and gas properties as no impairment indicators were identified. If we experience material declines in oil pricing

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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 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 $ 10.6 million and $ 8.8 million during the three months ended September 30, 2023 and 2022, respectively, and $ 31.8 million and $ 25.9 million during the nine months ended September 30, 2023 and 2022, respectively. The total tax benefit for the three months ended September 30, 2023 and 2022 was $ 1.9 million and $ 1.5 million, respectively, and $ 5.6 million and $ 4.4 million during the nine months ended September 30, 2023 and 2022, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of nil for the three months ended September 30, 2023 and 2022 and $( 3.2 ) million and $ 0.7 million during the nine months ended September 30, 2023 and 2022, respectively. The fair value of awards vested during the three months ended September 30, 2023 and 2022 was $ 0.2 million and $ 0.5 million, respectively, and $ 44.9 million and $ 21.9 million during the nine months ended September 30, 2023 and 2022, 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.

In June 2023, the Company’s stockholders approved the Amended and Restated Kosmos Energy Ltd. Long Term Incentive Plan, which authorized an additional 17.0 million shares of common stock available for issuance under the LTIP.

The following table reflects the outstanding restricted stock units as of September 30, 2023:


		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, 2022	4,916	$	4.18	12,041	$	5.61
Granted(1)	2,699	7.59		3,419	12.25
Forfeited(1)	( 214 )	5.46		( 192 )	7.98
Vested	( 2,755 )	3.86		( 2,949 )	8.22
Outstanding at September 30, 2023	4,646	5.72		12,319	6.56

__________________________________

(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, 2023, total equity-based compensation to be recognized on unvested restricted stock units is $ 37.5 million over a weighted average period of 1.77 years. At September 30, 2023, the Company had approximately 18.7 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 105.0 %. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from 0.2 % to 3.7 %.

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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 statutory 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.

Income before income taxes is composed of the following:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(In thousands)
United States	$	( 13,425 )	$	16,168	$	( 62,548 )	$	77,832
Foreign	150,966		313,799		392,904		459,139
Income before income taxes	$	137,541	$	329,967	$	330,356	$	536,971

For the three months ended, September 30, 2023 and 2022, our effective tax rate was 38 % and 33 %, respectively. For the nine months ended September 30, 2023 and 2022, our effective tax rate was 42 % and 37 %, respectively. For the three and nine months ended September 30, 2023 and 2022, our overall effective tax rates were impacted by:

• The difference in our 21 % U.S. income tax reporting rate and the statutory income tax rates applicable to our foreign operations, primarily in Ghana and Equatorial Guinea,

• Jurisdictions that have a 0 % statutory tax rate or that are tax exempt,

• Jurisdictions 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 Per Share

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
	(In thousands, except per share data)
Numerator:
Net income allocable to common stockholders	$	85,185	$	222,254	$	191,839	$	340,827




Denominator:
Weighted average number of shares outstanding:
Basic	460,108		455,840		459,477		455,158
Restricted stock units(1)	20,991		20,591		20,261		19,662
Diluted	481,099		476,431		479,738		474,820
Net income per share:
Basic	$	0.19	$	0.49	$	0.42	$	0.75
Diluted	$	0.18	$	0.47	$	0.40	$	0.72

__________________________________

(1) We excluded restricted stock units of 0.2 million for the three months ended September 30, 2022 and 0.1 million for the nine months ended September 30, 2022 from the computations of diluted net income per share because the effect would have been anti-dilutive.

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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. We have a $ 200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Greater Tortue FPSO.

Performance Obligations

As of September 30, 2023 and December 31, 2022, the Company had performance and supplemental bonds totaling $ 192.0 million and $ 205.2 million, respectively, related to bonding requirements stipulated by the BOEM and other third parties for anticipated plugging and abandonment costs of certain wells and the removal of certain facilities in our U.S. Gulf of Mexico fields.

14. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:


	September 30, 2023		December 31, 2022
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	131,208	$	80,598
Revenue payable	25,077		26,087
Current asset retirement obligations	10,884		1,732
General and administrative expenses	26,719		32,069
Interest	47,383		44,740
Income taxes	91,023		127,183
Taxes other than income	1,225		1,524
Derivatives	1,372		6,440
Other	3,899		4,833
	$	338,790	$	325,206

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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, 2023:


	September 30, 2023
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	302,534
Liabilities incurred during period	10,015
Liabilities settled during period	( 3,504 )
Revisions in estimated retirement obligations	10,340
Accretion expense	21,601
Ending asset retirement obligations	$	340,986

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,
	2023		2022		2023		2022
	(In thousands)
(Gain) loss on disposal of inventory	$	2,412	$	( 821 )	$	5,351	$	( 536 )
Loss on asset retirement obligations liability settlements	4,733		—		4,848		620

Other, net	3,910		603		7,665		( 1,404 )
Other expenses, net	$	11,055	$	( 218 )	$	17,864	$	( 1,320 )

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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, 2023, 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		Equatorial Guinea		Mauritania/Senegal		U.S. Gulf of Mexico		Corporate & Other		Eliminations		Total
	(In thousands)
Three months ended September 30, 2023
Revenues and other income:
Oil and gas revenue	$	348,366	$	75,014	$	—	$	102,968	$	—	$	—	$	526,348

Other income, net	—		—		—		746		80,826		( 81,374 )		198
Total revenues and other income	348,366		75,014		—		103,714		80,826		( 81,374 )		526,546
Costs and expenses:
Oil and gas production	90,737		24,700		—		23,345		—		—		138,782

Exploration expenses	( 58 )		2,931		3,698		1,913		1,806		—		10,290
General and administrative	2,475		1,209		2,543		3,291		51,018		( 35,416 )		25,120
Depletion, depreciation and amortization	77,688		14,654		297		38,948		760		—		132,347

Interest and other financing costs, net(1)	14,368		( 752 )		( 31,438 )		3,540		39,722		—		25,440
Derivatives, net	—		—		—		—		45,971		—		45,971
Other expenses, net	42,466		3,449		3,337		5,414		2,347		( 45,958 )		11,055
Total costs and expenses	227,676		46,191		( 21,563 )		76,451		141,624		( 81,374 )		389,005
Income (loss) before income taxes	120,690		28,823		21,563		27,263		( 60,798 )		—		137,541
Income tax expense	42,614		12,477		—		54		( 2,789 )		—		52,356
Net income (loss)	$	78,076	$	16,346	$	21,563	$	27,209	$	( 58,009 )	$	—	$	85,185

Consolidated capital expenditures, net	$	53,039	$	15,821	$	42,079	$	76,895	$	4,716	$	—	$	192,550

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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, 2023
Revenues and other income:
Oil and gas revenue	$	728,465	$	179,643	$	—	$	285,735	$	—	$	—	$	1,193,843

Other income, net	( 425 )		10		—		2,832		151,740		( 154,272 )		( 115 )
Total revenues and other income	728,040		179,653		—		288,567		151,740		( 154,272 )		1,193,728
Costs and expenses:
Oil and gas production	141,973		68,623		—		75,701		—		—		286,297

Exploration expenses	579		7,013		11,917		9,089		4,707		—		33,305
General and administrative	9,921		3,871		7,346		13,099		155,617		( 112,123 )		77,731
Depletion, depreciation and amortization	177,796		36,737		699		114,912		1,490		—		331,634

Interest and other financing costs, net(1)	42,535		( 2,138 )		( 87,087 )		9,632		111,437		—		74,379
Derivatives, net	—		—		—		—		42,162		—		42,162
Other expenses, net	38,811		3,402		6,058		8,215		3,527		( 42,149 )		17,864
Total costs and expenses	411,615		117,508		( 61,067 )		230,648		318,940		( 154,272 )		863,372
Income (loss) before income taxes	316,425		62,145		61,067		57,919		( 167,200 )		—		330,356
Income tax expense	112,478		25,837		—		1,119		( 917 )		—		138,517
Net income (loss)	$	203,947	$	36,308	$	61,067	$	56,800	$	( 166,283 )	$	—	$	191,839

Consolidated capital expenditures, net	$	202,517	$	40,777	$	191,830	$	125,215	$	8,288	$	—	$	568,627

As of September 30, 2023
Property and equipment, net	$	1,243,655	$	402,999	$	1,672,423	$	842,715	$	18,177	$	—	$	4,179,969
Total assets	$	3,320,522	$	1,738,886	$	2,507,496	$	3,934,860	$	21,048,238	$	( 27,580,601 )	$	4,969,401

______________________________________

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

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	Ghana(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	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	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 three and nine months ended September 30, 2022.

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	Nine Months Ended September 30,
	2023		2022
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	611,914	$	543,349
Acquisition of oil and gas properties	—		21,205
Proceeds on sale of assets	—		( 118,703 )
Adjustments:
Changes in capital accruals	25,441		1,511
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	31,061		35,570
Capitalized interest	( 99,920 )		( 57,489 )
Other	131		8,259
Total consolidated capital expenditures, net	$	568,627	$	433,702

______________________________________

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

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, 2022, 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 offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea and the U.S. Gulf of Mexico.

Globally, the impacts of Russia’s war in Ukraine, a potential recession, COVID-19 and other varying macroeconomic conditions have impacted supply and demand for oil and gas, which also resulted in significant variability in oil and gas prices, and could materially impact the Company’s business in future periods. 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

On September 15, 2023, the Company repaid the remaining outstanding principal amount of the GoM Term Loan in the amount of $137.5 million plus accrued interest using cash on hand, constituting payment in full. The GoM Term Loan was subsequently terminated pursuant to, and subject to the terms of, the GoM Term Loan.

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Ghana

During the third quarter of 2023, Ghana production averaged approximately 128,000 Boepd gross (43,600 Boepd net).

The Jubilee development drilling campaign continued to progress during the third quarter of 2023 bringing one producer well in the Jubilee Main Field online during the quarter and successfully starting up the Jubilee South East project with two producers online in July 2023. The Jubilee partnership brought an additional two water injection wells in the field online early in the fourth quarter of 2023 and accelerated the drilling of one additional producer well in the Jubilee Main Field and one additional water injection well related to Jubilee South East into the fourth quarter of 2023.

In connection with the approval of the Jubilee Phase 1 PoD in 2009, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to the Government of Ghana at no cost. As of January 1, 2023, the Jubilee partners had fulfilled this commitment, providing 200 Bcf of natural gas to the Government of Ghana. From 2018 through 2022, approximately 19 Bcf of the first 200 Bcf of natural gas was substituted from the TEN Fields in order to maintain consistent gas volumes to shore for Ghana domestic power purposes. Commencing on January 1, 2023, the volume of approximately 19 Bcf of Jubilee gas (in restoration of the amount originally substituted from TEN) has been sold to Ghana under the terms of the TAG GSA at $0.50 per MMBtu. The Jubilee partners have reached an interim agreement to sell Jubilee Field gas at a price of $2.90 per MMBtu to the Government of Ghana beyond the 19 Bcf from the Jubilee Field through November 2023, while the partners continue on-going discussions with the Government of Ghana regarding a long-term future gas sales agreement covering both the Jubilee and TEN Fields. During the second quarter of 2023, the operator submitted a draft amended plan of development for TEN, as well as a term sheet for a gas sales agreement covering future gas sales from both the Jubilee and TEN Fields, to the Government of Ghana. If the amended plan of development for TEN is not approved or delayed, it could lead to a curtailment or delay of investment and development activity in TEN.

U.S. Gulf of Mexico

Production from the U.S. Gulf of Mexico averaged approximately 15,700 Boepd net (~82% oil) for the third quarter of 2023.

The Kodiak #3 infill well located in Mississippi Canyon was brought online in April 2021. The well experienced production issues and was shut-in. In March 2022, the Company commenced operations to plug back and side-track the original Kodiak #3 infill well. The Kodiak-3ST well was brought online in early September 2022. 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 have been developed for remediation and are now expected to commence around the middle of 2024 given the better than forecast performance of the well this year.

The Winterfell development project continued to make progress during the third quarter of 2023. Drilling and completion of the three wells for the first phase of development under the Field Development Plan commenced in the third quarter of 2023 and first production for the project is targeted to be around the end of the first quarter of 2024. The first well has

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been drilled and completed. The host facility production handling agreement and midstream export agreements are expected to be completed by the end of 2023.

The Odd Job Field subsea pump installation project was approximately 67% complete as of the end of the third quarter of 2023 with an expected online date in the middle of 2024. The project is expected to extend the life and increase reserves of the Odd Job Field.

In July 2023, Kosmos spud the Tiberius infrastructure-led exploration prospect, which is located in block 964 of Keathley Canyon (33% working interest) in the Outer Wilcox play. In October 2023, we announced the well encountered approximately 75 meters (250 feet) of net oil pay in the primary Wilcox target. We are now conducting rock and fluid analysis to confirm the production potential of the reservoir and working with partners on subsea development options for the discovery.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 25,400 Bopd gross (8,900 Bopd net) in the third quarter of 2023.

The Ceiba Field and Okume Complex rig campaign is expected to commence shortly in the fourth quarter of 2023. The campaign is planned to include two production well workovers followed by drilling three in-fill production wells and one ILX well (Akeng Deep) in Block S.

Mauritania and Senegal

Greater Tortue Ahmeyim Unit

On Greater Tortue Ahmeyim, the following milestones have been achieved:

• Drilling: Earlier in the year, the operator successfully drilled and completed all four wells with expected production capacity significantly higher than what is required for first gas.

• Hub Terminal: Construction work is complete, and handover to operations was completed in August 2023.

• Subsea: Significant progress has been made on the revised plan to complete installation of the infield flowlines and subsea structures due to the previously announced delay in the subsea workstream. Work on the revised plan is expected to commence later this quarter with new contractors.

• FLNG: Construction and mechanical completion activities are finishing and pre-commissioning work is underway. The vessel is expected to sailaway later this quarter arriving on location early next year when hookup work is expected to commence.

• FPSO: Currently en route to Mauritania/Senegal and is now expected to arrive on location in the first quarter of 2024.

The critical path to first gas on Phase 1 of the Greater Tortue Ahmeyim project is now through the arrival, hookup and commissioning of the FPSO. The delivery of first gas in the first quarter of 2024 depends on the execution of this workstream, which has the potential to slip into the second quarter of 2024.

Yakaar and Teranga Discoveries

The Yakaar and Teranga discoveries continue to be analyzed as a joint development. During 2023 we have continued progressing appraisal studies, maturing concept design, and proposed to partners that the Yakaar and Teranga discoveries in the Cayar Offshore Profond Block be pursued as a commercial joint development. PETROSEN agreed to the proposal, however, BP was not able to reach alignment on important terms of the proposed joint development. On November 2, 2023, BP elected not to proceed with further development activities with the Yakaar and Teranga discoveries. In accordance with the provisions of the Contract for Exploration and Production Sharing of Hydrocarbons for the Cayar Offshore Profond Block (the “Contract”) and the related Joint Operating Agreement (the “JOA”), BP has now elected to permanently waive its rights to participate in the development of the Yakaar and Teranga discoveries under the Contract and the JOA. As provided in the JOA, Kosmos has assumed BP’s participating interest under the Contract and the JOA and has become operator of the Cayar Offshore Profond Block, subject to customary government approvals. The participating interests in the Cayar Offshore Profond Block is now:

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Kosmos 90% and PETROSEN 10%, subject to customary government approvals, with PETROSEN having the right to increase its participating interest after final investment decision and issuance of an exploitation authorization to up to 35%.

Results of Operations

All of our results, as presented in the table below, represent operations from Ghana, the U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the three and nine months ended September 30, 2023 and 2022 are included in the following tables:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	5,956		4,458		14,448		16,028
Gas (MMcf)	4,046		859		9,582		3,115
NGL (MBbl)	97		84		299		330
Total (MBoe)	6,727		4,685		16,344		16,877
Total (Boepd)	73,123		50,926		59,868		61,821

Revenues:
Oil sales	$	511,735	$	444,491	$	1,166,983	$	1,699,167
Gas sales	13,080		8,595		20,514		23,802
NGL sales	1,533		2,970		6,346		12,470
Total oil and gas revenue	$	526,348	$	456,056	$	1,193,843	$	1,735,439

Average oil sales price per Bbl	$	85.92	$	99.71	$	80.77	$	106.01
Average gas sales price per Mcf	3.23		10.01		2.14		7.64
Average NGL sales price per Bbl	15.80		35.36		21.22		37.79
Average total sales price per Boe	78.24		97.34		73.04		102.83

Costs:
Oil and gas production, excluding workovers	$	136,556	$	58,811	$	278,373	$	268,154
Oil and gas production, workovers	2,226		3,561		7,924		9,110
Total oil and gas production costs	$	138,782	$	62,372	$	286,297	$	277,264

Depletion, depreciation and amortization	$	132,347	$	106,313	$	331,634	$	386,961

Average cost per Boe:
Oil and gas production, excluding workovers	$	20.30	$	12.55	$	17.03	$	15.89
Oil and gas production, workovers	0.33		0.76		0.48		0.54
Total oil and gas production costs	20.63		13.31		17.51		16.43

Depletion, depreciation and amortization	19.67		22.69		20.29		22.93
Total	$	40.30	$	36.00	$	37.80	$	39.36

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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, 2023:


	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	—	—	1	0.39	—	—	3	1.16
TEN	—	—	—	—	—	—	5	1.02
Equatorial Guinea
Block S	—	—	—	—	1	0.34	—	—
Okume	—	—	—	—	—	—	1	0.40
U.S. Gulf of Mexico
Marmalard			1	0.11
Winterfell	—	—	1	0.25	—	—	1	0.25
Tiberius	1	0.33	—	—	—	—	—	—
Mauritania / Senegal
Mauritania BirAllah Block	—	—	—	—	2	0.56	—	—
Greater Tortue Ahmeyim Unit	—	—	—	—	1	0.27	—	—
Senegal Cayar Profond	—	—	—	—	3	0.90	—	—
Total	1	0.33	3	0.75	7	2.07	10	2.83

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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, 2023 compared to three months ended September 30, 2022


	Three Months Ended
	September 30,				Increase
	2023		2022		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	526,348	$	456,056	$	70,292

Other income, net	198		48		150
Total revenues and other income	526,546		456,104		70,442
Costs and expenses:
Oil and gas production	138,782		62,372		76,410
Facilities insurance modifications, net	—		494		(494)
Exploration expenses	10,290		17,215		(6,925)
General and administrative	25,120		24,007		1,113
Depletion, depreciation and amortization	132,347		106,313		26,034

Interest and other financing costs, net	25,440		29,796		(4,356)
Derivatives, net	45,971		(113,842)		159,813
Other expenses, net	11,055		(218)		11,273
Total costs and expenses	389,005		126,137		262,868
Income before income taxes	137,541		329,967		(192,426)
Income tax expense	52,356		107,713		(55,357)
Net income	$	85,185	$	222,254	$	(137,069)

Oil and gas revenue. Oil and gas revenue increased by $70.3 million during the three months ended September 30, 2023, as compared to the three months ended September 30, 2022 primarily as a result of the increased sales volumes due to the timing of our international oil liftings offset by lower average oil prices. We sold 6,727 MBoe at an average realized price per barrel equivalent of $78.24 during the three months ended September 30, 2023 and 4,685 MBoe at an average realized price per barrel equivalent of $97.34 during the three months ended September 30, 2022.

Oil and gas production. Oil and gas production costs increased by $76.4 million during the three months ended September 30, 2023, as compared to the three months ended September 30, 2022 primarily as a result of increased sales volumes due to the timing of our international oil liftings and higher production costs per barrel driven by field production mix in our Ghana business unit.

Exploration expenses. Exploration expenses decreased by $6.9 million during the three months ended September 30, 2023, as compared to the three months ended September 30, 2022 primarily a 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.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $26.0 million during the three months ended September 30, 2023, as compared with the three months ended September 30, 2022 primarily as a result of increased sales volumes during the quarter.

Derivatives, net. During the three months ended September 30, 2023 and 2022, we recorded a loss of $46.0 million and a gain of $113.8 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.

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Income tax expense (benefit). For the three months ended September 30, 2023 and 2022, changes to our effective tax rates are driven by which tax jurisdictions our income before income taxes is generated. The jurisdictions in which we operate have statutory tax rates ranging from 0% to 35%.

Nine months ended September 30, 2023 compared to nine months ended September 30, 2022


	Nine Months Ended
	September 30,				Increase
	2023		2022		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	1,193,843	$	1,735,439	$	(541,596)
Gain on sale of assets	—		471		(471)
Other income, net	(115)		143		(258)
Total revenues and other income	1,193,728		1,736,053		(542,325)
Costs and expenses:
Oil and gas production	286,297		277,264		9,033
Facilities insurance modifications, net	—		7,246		(7,246)
Exploration expenses	33,305		118,656		(85,351)
General and administrative	77,731		74,424		3,307
Depletion, depreciation and amortization	331,634		386,961		(55,327)

Interest and other financing costs, net	74,379		92,317		(17,938)
Derivatives, net	42,162		243,534		(201,372)

Other expenses, net	17,864		(1,320)		19,184
Total costs and expenses	863,372		1,199,082		(335,710)
Income before income taxes	330,356		536,971		(206,615)
Income tax expense	138,517		196,144		(57,627)
Net income	$	191,839	$	340,827	$	(148,988)

Oil and gas revenue. Oil and gas revenue decreased by $541.6 million during the nine months ended September 30, 2023, as compared to the nine months ended September 30, 2022 primarily as a result of lower average oil prices for the nine months ended September 30, 2023. We sold 16,344 MBoe at an average realized price per barrel equivalent of $73.04 during the nine months ended September 30, 2023 and 16,877 MBoe at an average realized price per barrel equivalent of $102.83 during the nine months ended September 30, 2022.

Oil and gas production. Oil and gas production costs increased by $9.0 million during the nine months ended September 30, 2023, as compared to the nine months ended September 30, 2022 primarily as a result of higher production costs per barrel in our Ghana business unit.

Exploration expenses. Exploration expenses decreased by $85.4 million during the nine months ended September 30, 2023, as compared to the nine months ended September 30, 2022. During the during the nine months ended September 30, 2022, $64.2 million of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania were written off to exploration expense with the expiration of the exploration period of Block C8 and approximately $10.9 million was incurred related to the two abandoned Ntomme step out wells.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $55.3 million during the nine months ended September 30, 2023, as compared with the nine months ended September 30, 2022 primarily as a result lower depletion cost per Boe in our Ghana business unit due to lower cost basis in our TEN Fields, resulting from an impairment charge recognized on the TEN Fields for the year ended December 31, 2022.

Interest and other financing costs, net. Interest and other financing costs, net decreased $17.9 million during the nine months ended September 30, 2023, as compared to the nine months ended September 30, 2022, primarily as a result of

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increased capitalized interest related to the Greater Tortue Ahmeyim project partially offset by increased interest expenses related to higher interest rates.

Derivatives, net. During the nine months ended September 30, 2023 and 2022, we recorded a loss of $42.2 million and a loss of $243.5 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, 2023 and 2022, changes to our effective tax rates are driven by which tax jurisdictions our income before income taxes is generated. The jurisdictions in which we operate have statutory tax rates ranging from 0% to 35%.

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 a significant decrease in oil prices could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could also 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 2023.

As such, our 2023 capital budget is based on our exploitation and production plans for Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, our infrastructure-led exploration and appraisal program in the U.S. Gulf of Mexico and Equatorial Guinea, and our appraisal and development activities in the U.S. Gulf of Mexico, Mauritania and Senegal.

Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation, 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, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners and their alignment with respect to capital plans, 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.

As of September 30, 2023, borrowings under the Facility totaled $925.0 million and the undrawn availability under the Facility was $220.1 million. In October 2023, during the Fall 2023 redetermination, the Company’s lending syndicate approved a borrowing base capacity of $1.25 billion increasing undrawn availability by approximately $104.9 million. As of September 30, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million.

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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, 2023 and 2022:


	Nine Months Ended
	September 30,
	2023		2022
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	471,394	$	863,236

Borrowings under long-term debt	300,000		—
Proceeds on sale of assets	—		118,703
	771,394		981,939
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	611,914		543,349
Acquisition of oil and gas properties	—		21,205
Notes receivable from partners	46,632		28,188
Payments on long-term debt	145,000		322,500
Tax withholdings on restricted stock units	11,811		2,753
Dividends	166		655
Deferred financing costs	534		6,288
	816,057		924,938
Increase (decrease) in cash, cash equivalents and restricted cash	$	(44,663)	$	57,001

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2023 was $471.4 million compared with net cash provided by operating activities for the nine months ended September 30, 2022 of $863.2 million. The decrease in cash provided by operating activities in the nine months ended September 30, 2023 when compared to the same period in 2022 is primarily a result of lower average oil prices for the nine months ended September 30, 2023.

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The following table presents our liquidity and financial position as of September 30, 2023 and December 31, 2022:


	September 30, 2023		December 31, 2022
	(In thousands)
Borrowings under the Facility	$	925,000	$	625,000
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	—		145,000
Total long-term debt	2,425,000		2,270,000
Cash and cash equivalents	138,742		183,405
Total restricted cash	3,416		3,416
Net debt	$	2,282,842	$	2,083,179

Availability under the Facility	$	220,083	$	618,034
Availability under the Corporate Revolver	$	250,000	$	250,000
Available borrowings plus cash and cash equivalents	$	608,825	$	1,051,439

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 appraisal and development activities in Ghana, the U.S. Gulf of Mexico, Mauritania and Senegal; and

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

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.

2023 Capital Program

We estimate we will spend approximately $800 million of capital for the year ending December 31, 2023, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

• Approximately $325 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 $400 million related to the development of Jubilee South East in Ghana, Phase 1 of Greater Tortue Ahmeyim in Mauritania and Senegal, and Winterfell in the U.S. Gulf of Mexico;

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• Approximately $75 million related to progressing our infrastructure-led exploration and appraisal programs in the U.S. Gulf of Mexico and Equatorial Guinea, as well as the appraisal plans of our greater gas resources in Mauritania and Senegal, including Phase 2 of Greater Tortue Ahmeyim, BirAllah and Yakaar-Teranga.

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. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. As of September 30, 2023, borrowings under the Facility totaled $925.0 million and the undrawn availability under the Facility was $220.1 million. In October 2023, during the Fall 2023 redetermination, the Company’s lending syndicate approved a borrowing base capacity of $1.25 billion increasing the undrawn availability by approximately $104.9 million. 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 and Equatorial Guinea

On November 23, 2022, the Company amended the Facility to update the interest rate benchmark from LIBOR to term SOFR, effective as of April 19, 2023. On September 29, 2023, the Company amended the Facility to accede Kosmos Energy Ghana Investments and Kosmos Energy Ghana Holdings Limited, to the Facility as obligors. As a result, the additional interests in Jubilee and TEN that were acquired in the October 2021 acquisition of Anadarko WCTP are now included when calculating the borrowing base amount for the Facility, effective as of October 1, 2023. On October 19, 2023, the Company amended the Facility to modify the amortization schedule in order to reduce the number of repayment installments from seven to six equal installments, with the first repayment installment scheduled on October 1, 2024, rather than March 31, 2024. There was no change to the final maturity date or final repayment date.

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 October 1, 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, 2023, 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.

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 assets. We were in compliance with the financial covenants contained in the Facility as of September 30, 2023 (the most recent assessment date). The Facility contains customary cross default provisions.

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Corporate Revolver

The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. On November 23, 2022, the Company amended the Corporate Revolver to update the interest rate benchmark from compounded SOFR to term SOFR. As of September 30, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million with an expiration date of December 31, 2024.

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

GoM Term Loan

In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. On September 15, 2023, the Company repaid the remaining outstanding principal amount of $137.5 million plus accrued interest using cash on hand, constituting payment in full. The GoM Term Loan was subsequently terminated pursuant to, and subject to the terms of, the GoM Term Loan.

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Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2023 and the weighted average interest rates expected to be paid on the Facility and Corporate Revolver 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,
	2023(2)			2024			2025			2026			2027			Thereafter			Total		2023
	(In thousands, except percentages)
Fixed rate debt:
7.125% Senior Notes	$	—		$	—		$	—		$	650,000		$	—		$	—		$	650,000	$	613,444
7.750% Senior Notes	—			—			—			—			400,000			—			$	400,000	$	370,044
7.500% Senior Notes	—			—			—			—			—			450,000			450,000		403,574

Variable rate debt:
Weighted average interest rate	9.22		%	9.38		%	8.59		%	8.69		%	8.95		%	—		%
Facility(1)	$	—		$	243,047		$	227,450		$	279,282		$	175,221		$	—		$	925,000	$	925,000


Total principal debt repayments(3)	$	—		$	243,047		$	227,450		$	929,282		$	575,221		$	450,000		$	2,425,000
Interest & commitment fee payments on long-term debt	62,609			195,878			160,847			116,530			53,177			16,875			605,916
Operating leases(4)	1,015			4,107			4,178			4,249			4,194			6,652			24,395
Purchase obligations(5)	48,764			34,976			—			—			—			—			83,740

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(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, 2023. 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. In October 2023 the Company’s lending syndicate approved a borrowing base capacity of $1.25 billion increasing the undrawn availability by approximately $104.9 million and the Company amended the Facility to modify the amortization schedule with the first repayment installment scheduled on October 1, 2024, rather than March 31, 2024.

(2) Represents the period October 1, 2023 through December 31, 2023.

(3) The amounts included in the table represent principal maturities only.

(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. 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.

We have a commitment to drill 3 development wells and one exploration well in Equatorial Guinea. We have a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Greater Tortue FPSO.

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal, which obligate us separately to finance the respective national oil companies’ share of certain development costs. Kosmos’ total share for the two agreements combined is currently estimated at approximately $300.0 million, of which $243.6 million has been incurred through September 30, 2023, excluding accrued interest. These amounts will be repaid through the national oil companies’ share of future revenues.

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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, 2022.

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 a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions on us and the overall business environment;

• the impacts of Russia’s war in Ukraine and potential instability in the Middle East following Hamas’ attack on Israel and the effects these events have 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, applicable monetary/foreign exchange sectors 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;

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• military operations, civil unrest, outbreaks of disease, including the impact of the COVID-19 pandemic, terrorist acts, wars or embargoes;

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

• our vulnerability to severe weather events, including, but not limited to, tropical storms and hurricanes, and the physical effects of climate change;

• 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;

• our ability to obtain surety or performance bonds on commercially reasonable terms;

• 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, 2023:


	Derivative Contracts Assets (Liabilities)
	Commodities
	(In thousands)
Fair value of contracts outstanding as of December 31, 2022	$	2,688
Changes in contract fair value	(52,467)
Contract maturities	21,478
Fair value of contracts outstanding as of September 30, 2023	$	(28,301)

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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 2023 ranged between $71.71 and $97.92 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first nine months of 2023.

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, 2023. 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		2023(1)
												(In thousands)
2023:
Oct - Dec	Three-way collars	Dated Brent	1,500	$	1.34	$	49.17	$	71.67	$	107.58	$	(2,884)
Oct - Dec	Two-way collars	Dated Brent	1,250	1.69		—		72.00		112.00		(2,391)


2024:
Jan - Dec	Three-way collars	Dated Brent	4,000	1.31		45.00		70.00		96.25		(8,720)
Jan - Jun	Two-way collars	Dated Brent	2,000	1.24		—		65.00		85.00		(14,395)
Jan - Dec	Two-way collars	Dated Brent	2,000	0.46		—		70.00		100.00		89

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(1) Fair values are based on the average forward oil prices on September 30, 2023.

At September 30, 2023, our open commodity derivative instruments were in a net liability position of $28.3 million. As of September 30, 2023, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $44.9 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $35.1 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, which as of September 30, 2023 total $925.0 million and have a weighted average interest rate of 9.2%, 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 $4.9 million interest expense per year. The commitment fees on the undrawn availability under the Facility and the Corporate Revolver are not subject to changes in interest rates. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. Additionally, a change in the market interest rates could impact interest costs associated with future debt issuances or any future borrowings.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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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, 2023, 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, 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 6, 2023	/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
10.1						Amended and Restated Facility Agreement, amended as of October 19 , 2023, among Kosmos Energy Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC, Kosmos Energy Equatorial Guinea, Kosmos Energy Ghana Investments, Kosmos Energy Ghana Holdings Limited, Kosmos Equatorial Guinea, Inc., Kosmos International Petroleum , Inc. , ABSA Bank Limited, Credit Agricole Corporate and Investment Bank, ING Belgium SA/NV, Natixis, N.B.S.A Limited, Societe Generale, London Branch, The Standard Bank of South Africa Limited, Isle of Man Branch, Standard Chartered Bank, and SMBC Bank International PLC.

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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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

10.1 Amended and Restated Facility Agreement, amended as ofOctober 19, 2023, among Kosmos Energy Finance International, Kosmos Energy Operating, Kosmos Energy International, Kosmos Energy Development, Kosmos Energy Ghana HC, Kosmos Energy Equatorial Guinea, Kosmos Energy Ghana Investments, Kosmos Energy Ghana Holdings Limited, Kosmos Equatorial Guinea, Inc., Kosmos InternationalPetroleum, Inc.,ABSA Bank Limited, Credit Agricole Corporate and Investment Bank, ING Belgium SA/NV, Natixis, N.B.S.A Limited, Societe Generale, London Branch, The Standard Bank of South Africa Limited, Isle of Man Branch, Standard Chartered Bank, and SMBC Bank International PLC. 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, 2023

Exhibits