kos-20250930

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2025


☐			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 October 30, 2025
Common Shares, $0.01 par value						478,326,954

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			35
Item 3. Quantitative and Qualitative Disclosures about Market Risk			48
Item 4. Controls and Procedures			51

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			51
Item 1A. Risk Factors			51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			51
Item 3. Defaults Upon Senior Securities			51
Item 4. Mine Safety Disclosures			51
Item 5. Other Information			52
Signatures			53
Item 6. Exhibits			53
Index to Exhibits			54

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KOSMOS ENERGY LTD.

GLOSSARY AND SELECTED ABBREVIATIONS

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


“2D seismic data”						Two‑dimensional seismic data, serving as interpretive data that allows a view of a vertical cross‑section beneath a prospective area.
“3D seismic data”						Three‑dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
“ANP-STP”						Agencia Nacional Do Petroleo De Sao Tome E Principe.
“API”						A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.
“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.
“3.125% Convertible Senior Notes”						3.125% Convertible Senior Notes due 2030.
“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.
“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) debt modifications and extinguishments, (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.

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“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 vessel.
“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.
“GNPC”						Ghana National Petroleum Corporation.
“GoA field life coverage ratio”						The “GoA field life coverage ratio” is broadly defined, as (a) total PV-10 of the Gulf of America business unit using the Proved or Probable Reserves as set forth in the most recently delivered reserve report to (b) outstanding principal amount of the GoA Term Loan as of such date.
“GoA net leverage ratio”						The “GoA net leverage ratio” is broadly defined, as of any date of determination, the ratio of (a) total net debt of the Gulf of America business unit, as of such date to (b) EBITDAX of the Gulf of America business unit for the rolling period ending on such date (or in the case of any calculation of the total net leverage ratio on any date other than the last day of a rolling period, for the most recently ended rolling period for which financial statements are available).
“GoA Term Loan Facility”						Senior Secured Term Loan Credit Agreement dated September 24, 2025
“Greater Tortue Ahmeyim”						Ahmeyim and Guembeul discoveries.
“GTA UUOA”						Unitization and Unit Operating Agreement covering the Greater Tortue Ahmeyim Unit.
“HLS”						Heavy Louisiana Sweet.
“Jubilee UUOA”						Unitization and Unit Operating Agreement covering the Jubilee Unit.
“Interest cover ratio”						The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.
“LNG”						Liquefied natural gas.
“Loan life cover ratio”						The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets to (y) the aggregate loan amounts outstanding under the Facility.
“LSE”						London Stock Exchange.
“LTIP”						Long Term Incentive Plan.
“MBbl”						Thousand barrels of oil.
“MBoe”						Thousand barrels of oil equivalent.
“Mcf”						Thousand cubic feet of natural gas.
“Mcfpd”						Thousand cubic feet per day of natural gas.

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“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.
“8.750% Senior Notes”						8.750% Senior Notes due 2031.
“SMH”						Societe Mauritanienne des Hydrocarbures
“Stratigraphy”						The study of the composition, relative ages and distribution of layers of sedimentary rock.
“Stratigraphic trap”						A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.
“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.
“TAG GSA”						TEN Associated Gas - Gas Sales Agreement.
“TEN”						Tweneboa, Enyenra and Ntomme.

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“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, 2025		December 31, 2024
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	64,032	$	84,972

Receivables	103,330		164,959
Inventories	164,392		170,871
Prepaid expenses and other	14,776		16,414
Derivatives	19,037		8,916
Total current assets	365,567		446,132

Property and equipment, net	4,208,535		4,444,221

Other assets:
Restricted cash	14,032		305
Long-term receivables	451,540		385,463
Deferred tax assets	4,024		4,717
Derivatives	3,025		512
Other	43,018		27,638
Total assets	$	5,089,741	$	5,308,988
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	200,809	$	349,994
Accrued liabilities	251,310		244,954
Current maturities of long-term debt	250,000		—
Derivatives	3,239		—
Total current liabilities	705,358		594,948
Long-term liabilities:
Long-term debt, net	2,728,500		2,744,712
Derivatives	278		—
Asset retirement obligations	399,719		406,886
Deferred tax liabilities	313,426		313,433
Other long-term liabilities	43,673		48,585
Total long-term liabilities	3,485,596		3,513,616
Stockholders’ equity:
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at September 30, 2025 and December 31, 2024	—		—
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 522,517,241 and 516,158,749 issued at September 30, 2025 and December 31, 2024, respectively	5,225		5,162
Additional paid-in capital	2,535,684		2,514,739
Accumulated deficit	(1,405,115)		(1,082,470)
Treasury stock, at cost, 44,263,269 shares at September 30, 2025 and December 31, 2024, respectively	(237,007)		(237,007)
Total stockholders’ equity	898,787		1,200,424
Total liabilities and stockholders’ equity	$	5,089,741	$	5,308,988

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2025		2024		2025		2024
Revenues and other income:
Oil and gas revenue	$	310,959	$	407,794	$	993,729	$	1,277,797
Gain on sale of assets	—		—		600		—
Other income, net	270		37		849		109
Total revenues and other income	311,229		407,831		995,178		1,277,906
Costs and expenses:
Oil and gas production	147,696		133,471		558,122		377,822
Exploration expenses	54,948		14,697		68,686		39,992
General and administrative	12,886		23,298		58,215		76,724
Depletion, depreciation and amortization	141,514		120,728		413,449		311,750

Interest and other financing costs, net	57,919		22,112		164,595		75,839
Derivatives, net	(3,646)		(15,254)		(18,480)		5,716
Other expenses, net	6,384		2,227		14,854		6,418
Total costs and expenses	417,701		301,279		1,259,441		894,261
Income (loss) before income taxes	(106,472)		106,552		(264,263)		383,645
Income tax expense	17,827		61,578		58,382		187,215
Net income (loss)	$	(124,299)	$	44,974	$	(322,645)	$	196,430

Net income (loss) per share:
Basic	$	(0.26)	$	0.10	$	(0.68)	$	0.42
Diluted	$	(0.26)	$	0.09	$	(0.68)	$	0.41

Weighted average number of shares used to compute net income (loss) per share:
Basic	478,254		471,816		477,344		470,491
Diluted	478,254		479,190		477,344		478,701

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
2025:
Balance as of December 31, 2024	516,159	$	5,162	$	2,514,739	$	(1,082,470)	$	(237,007)	$	1,200,424


Equity-based compensation	—	—		8,362		—		—		8,362
Restricted stock units	6,009	60		(60)		—		—		—

Net loss	—	—		—		(110,606)		—		(110,606)
Balance as of March 31, 2025	522,168	5,222		2,523,041		(1,193,076)		(237,007)		1,098,180

Equity-based compensation	—	—		7,345		—		—		7,345
Restricted stock units	315	3		(3)		—		—		—
Tax withholdings and cash settlements on restricted stock units	—	—		(1)		—		—		(1)
Net loss	—	—		—		(87,740)		—		(87,740)
Balance as of June 30, 2025	522,483	5,225		2,530,382		(1,280,816)		(237,007)		1,017,784

Equity-based compensation	—	—		5,302		—		—		5,302
Restricted stock units	34	—		—		—		—		—

Net loss	—	—		—		(124,299)		—		(124,299)
Balance as of September 30, 2025	522,517	$	5,225	$	2,535,684	$	(1,405,115)	$	(237,007)	$	898,787

2024:
Balance as of December 31, 2023	504,393	$	5,044	$	2,536,621	$	(1,272,321)	$	(237,007)	$	1,032,337

Capped call transactions	—	—		(49,800)		—		—		(49,800)
Equity-based compensation	—	—		7,333		—		—		7,333
Restricted stock units	11,373	114		(114)		—		—		—
Tax withholdings and cash settlements on restricted stock units	—	—		(9,921)		—		—		(9,921)
Net income	—	—		—		91,686		—		91,686
Balance as of March 31, 2024	515,766	5,158		2,484,119		(1,180,635)		(237,007)		1,071,635

Equity-based compensation	—	—		10,487		—		—		10,487
Restricted stock awards and units	241	2		(2)		—		—		—
Tax withholdings and cash settlements on restricted stock units	—	—		(1)		—		—		(1)
Net income	—	—		—		59,770		—		59,770
Balance as of June 30, 2024	516,007	5,160		2,494,603		(1,120,865)		(237,007)		1,141,891

Equity-based compensation	—	—		10,034		—		—		10,034
Restricted stock units	73	1		(1)		—		—		—
Tax withholdings and cash settlements on restricted stock units	—	—		1		—		—		1
Net income	—	—		—		44,974		—		44,974
Balance as of September 30, 2024	516,080	$	5,161	$	2,504,637	$	(1,075,891)	$	(237,007)	$	1,196,900

See accompanying notes.

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KOSMOS ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2025		2024
Operating activities
Net income (loss)	$	(322,645)	$	196,430
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization (including deferred financing costs)	419,111		318,564
Deferred income taxes	686		11,280
Unsuccessful well costs and leasehold impairments	51,373		3,872

Change in fair value of derivatives	(10,675)		11,808
Cash settlements on derivatives, net (including $7.3 million and $(10.0) million on commodity hedges during 2025 and 2024)	2,801		(14,754)
Equity-based compensation	21,009		27,849
Gain on sale of assets	(600)		—
Debt modifications and extinguishments	—		24,794
Other	(11,492)		(12,126)
Changes in assets and liabilities:
(Increase) decrease in receivables	76,488		(33,304)
Increase in inventories and prepaid expenses	(42)		(2,320)
Decrease in accounts payable and accrued liabilities	(127,302)		(29,591)
Net cash provided by operating activities	98,712		502,502
Investing activities
Oil and gas assets	(244,133)		(772,238)


Notes receivable and other investing activities	(86,791)		(2,575)
Net cash used in investing activities	(330,924)		(774,813)
Financing activities
Borrowings under long-term debt	375,000		275,000
Payments on long-term debt	(150,000)		(350,000)
Net proceeds from issuance of senior notes	—		885,285
Repurchase of senior notes	—		(499,515)
Purchase of capped call transactions	—		(49,800)

Other financing costs	(1)		(35,534)
Net cash provided by financing activities	224,999		225,436
Net decrease in cash, cash equivalents and restricted cash	(7,213)		(46,875)
Cash, cash equivalents and restricted cash at beginning of period	85,277		98,761
Cash, cash equivalents and restricted cash at end of period	$	78,064	$	51,886

Supplemental cash flow information
Cash paid for:

Income taxes, net of refund received	$	90,324	$	232,923

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 Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success. 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 Gulf of America.

Going Concern

The Company’s consolidated financial statements included herein have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The normal course of business is dependent on, among other things, the Company’s ability to operate profitably, to generate cash flows from operations, and to pursue appropriate financing arrangements to support its working capital requirements. As an example, in July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility to make it less restrictive for the two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. This amendment was intended to align the covenant calculation with recent business operations, lower realized oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations.

Following the July 2025 amendment, the Company has continued to experience lower than expected realized oil prices, delayed cargo sales from Jubilee, and a slower GTA LNG production ramp-up, all of which have contributed to a reduction in forecasted EBITDAX and the resulting need to increase unplanned drawn debt levels under the Facility. Management has evaluated the Company’s future liquidity and forecasted operating results and the Company’s ability to comply with the financial covenants under its debt instruments for the next twelve months from the date of issuance of these financial statements, and based on this analysis, there are circumstances under which the Company may not be in compliance with the debt cover ratio under the Facility on the future measurement dates, to be assessed in March 2026 and September 2026.

Based on this analysis, management has developed a mitigation plan that, if executed successfully, it believes will satisfy the debt cover ratio under the Facility on the March 2026 and the September 2026 assessment dates. The plan includes actions to reduce operating expenditures at the TEN fields in Ghana, to reduce general and administrative expenses, and the potential monetization of existing hedges to expedite the realization of hedge settlements. We may also consider other potential opportunities or strategic transactions, such as acquisitions and/or dispositions. However, there can be no assurance that this mitigation plan will be successfully executed if needed.

In the event the mitigation plan is unsuccessful, failure to satisfy the debt cover ratio covenant under the Facility, without a timely cure, waiver or amendment, would be considered an event of default. If necessary, the Company intends to work with the Facility lenders to waive, modify and/or amend the debt cover ratio, as it has successfully done in the past, but there can be no assurance that the Facility lenders will agree to waive, modify and/or amend the debt cover ratio covenant. If an event of default exists under the Facility and is not otherwise waived by the lenders, then the lenders could take various actions, including cancelling any outstanding commitments and accelerating the maturity of amounts due thereunder, among other things. An acceleration of amounts due under the Facility could also trigger the cross-default provisions under our Senior Notes and the GoA Term Loan Facility.

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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, 2024, included in our annual report on Form 10-K.

Reclassifications

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

Cash, Cash Equivalents and Restricted Cash


	September 30, 2025		December 31, 2024
	(In thousands)
Cash and cash equivalents	$	64,032	$	84,972

Restricted cash - long-term	14,032		305
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows	$	78,064	$	85,277

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. Restricted cash – long-term as of September 30, 2025 primarily consists of collateral posted to support performance bonds in the Gulf of America. When our debt cover ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our debt cover ratio was 2.54x, partially due to pre-production operating costs associated with the GTA Phase 1 project. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance through 2025.

Joint Interest Billings

The Company’s joint interest billings consist of receivables from partners with interests in common oil and natural 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 $148.4 million and $167.5 million of materials and supplies and $16.0 million and $3.4 million of hydrocarbons as of September 30, 2025 and December 31, 2024, 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

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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 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,
	2025		2024		2025		2024
	(In thousands)
Revenues from contracts with customers:
Ghana	$	143,134	$	237,725	$	508,818	$	828,279
Equatorial Guinea	40,753		71,267		137,631		187,328
Mauritania/Senegal	39,343		—		62,279		—
Gulf of America	88,693		103,476		293,572		267,000
Total revenues from contracts with customers	311,923		412,468		1,002,300		1,282,607
Provisional oil sales contracts	(964)		(4,674)		(8,571)		(4,810)
Oil and gas revenue	$	310,959	$	407,794	$	993,729	$	1,277,797

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.

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Recent Accounting Standards

Recently Adopted

In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” The amendment requires disclosures of significant segment expenses that are regularly provided to the chief operating decision maker (“CODM”) and included within each reported measure of segment profit or loss, an amount and description of its composition for other segment items, and interim disclosures of a reportable segment’s profit or loss and assets. The amendments are effective for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024.

Not Yet Adopted

In December 2023, the FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures (Topic 740).” The amendments focus on income tax disclosures around effective tax rates and cash income taxes paid. The amendments in the ASU are effective for annual periods beginning after December 15, 2024. Early adoption is permitted, however, we do not plan to early adopt ASU 2023-09. The Company is currently assessing the impact of this standard on its financial statement disclosures. While the adoption of this ASU will modify our disclosures, we do not expect it to have an impact on our consolidated balance sheets or statements of operations or cash flows in our consolidated financial statements.

In November 2024, the FASB issued ASU 2024-03, “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses”. The amendments in ASU 2024-03 require more detailed disclosures about specified categories of costs and expenses included in certain expense captions presented on the face of the income statement. This ASU is effective for fiscal years beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The Company is currently assessing the impact of this standard on its financial statement disclosures.

In November 2024, the FASB issued ASU 2024-04, “Debt - Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments.” The amendments in ASU 2024-04 clarify the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as an induced conversion. The amendments in the ASU are effective for annual periods beginning after December 15, 2025. Early adoption is permitted, however, we do not plan to early adopt ASU 2024-04. The Company is currently assessing the impact this standard will have on its consolidated financial statements.

3. Receivables

Receivables consisted of the following:


	September 30, 2025		December 31, 2024
	(In thousands)
Joint interest billings, net	$	16,891	$	33,120
Oil and gas sales	59,212		89,694
Other current receivables	27,227		42,145
Total receivables	$	103,330	$	164,959

Long-term receivables	$	451,540	$	385,463

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 as current and long-term receivables based on when collection is expected to occur.

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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 and production costs incurred for the GTA Phase 1 project through the Commercial Operations Date of the Gimi FLNG vessel. The Commercial Operations Date of the Gimi FLNG vessel was achieved in June 2025 following the successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum. As of September 30, 2025 and December 31, 2024, the principal balance due from the national oil companies was $355.5 million and $280.1 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. As of September 30, 2025 and December 31, 2024, accrued interest on the balance due from the national oil companies was $74.6 million and $56.6 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. Interest income on the long-term notes receivable was $6.5 million and $4.7 million for the three months ended September 30, 2025 and 2024, respectively, and $18.0 million and $14.0 million for the nine months ended September 30, 2025 and 2024, respectively.

4. Property and Equipment

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


	September 30, 2025		December 31, 2024
	(In thousands)
Oil and gas properties:
Proved properties	$	8,453,867	$	8,342,353
Unproved properties	399,539		386,292
Total oil and gas properties	8,853,406		8,728,645
Accumulated depletion	(4,648,519)		(4,288,215)
Oil and gas properties, net	4,204,887		4,440,430

Other property	67,486		66,675
Accumulated depreciation	(63,838)		(62,884)
Other property, net	3,648		3,791

Property and equipment, net	$	4,208,535	$	4,444,221

We recorded depletion expense of $131.7 million and $110.4 million for the three months ended September 30, 2025 and 2024, respectively, and $384.8 million and $283.7 million for the nine months ended September 30, 2025 and 2024, respectively. During the nine months ended September 30, 2025, additions to our proved properties primarily related to development costs associated with the first phase of the GTA development in Mauritania and Senegal and infill development in the Jubilee Field in Ghana.

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5. 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, 2025.


	September 30, 2025
	(In thousands)
Beginning balance	$	196,202
Additions to capitalized exploratory well costs pending the determination of proved reserves	15,324
Reclassification due to determination of proved reserves	—
Capitalized exploratory well costs charged to expense	—
Ending balance	$	211,526

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, 2025		December 31, 2024
	(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 five years	71,115		63,552
Exploratory well costs capitalized for a period of six to ten years	140,411		132,650
Ending balance	$	211,526	$	196,202
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, 2025, 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 Tiberius discovery in Keathley Canyon Block 964 in the Outer Wilcox play in the Gulf of America.

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 March 2024, the current phase of the Cayar Block exploration license was extended an additional two years to July 2026. The Yakaar and Teranga discoveries are being analyzed as a joint development. During 2025, we are working with the partnership to finalize the concept design.

Tiberius Discovery — In July 2023, we spud the Tiberius infrastructure-led exploration prospect located in Block 964 of Keathley Canyon in the Gulf of America, which encountered hydrocarbon pay. Initial fluid and core analysis supports the production potential of the well, with characteristics analogous with similar nearby discoveries in the Wilcox trend. In March 2024, we completed the acquisition of an additional 16.7% participating interest in the Keathley Canyon Blocks 920 and 964, offshore Gulf of America. As a result of the transaction, Kosmos’ participating interest in the Tiberius discovery area increased from 33.3% to 50.0%. The Tiberius project is being analyzed as a phased development with discussions currently ongoing with our partner to finalize the development plan. Following additional evaluation, a final investment decision for the development of the project is expected to be made.

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6. Debt


	September 30, 2025		December 31, 2024
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,125,000	$	900,000
7.125% Senior Notes	250,000		250,000
7.750% Senior Notes	350,000		350,000
7.500% Senior Notes	400,274		400,274
8.750% Senior Notes	500,000		500,000
3.125% Convertible Senior Notes	400,000		400,000

Total long-term debt	3,025,274		2,800,274
Unamortized deferred financing costs and discounts(1)	(46,774)		(55,562)
Total debt, net	2,978,500		2,744,712
Less: Current maturities of long-term debt	(250,000)		—
Long-term debt, net	$	2,728,500	$	2,744,712

(1)Includes $25.8 million and $30.4 million of unamortized deferred financing costs related to the Facility, $11.4 million and $14.1 million of unamortized deferred financing costs and discounts related to the Senior Notes, and $9.6 million and $11.1 million of unamortized deferred financing costs related to the 3.125% Convertible Senior Notes as of September 30, 2025 and December 31, 2024, respectively.

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As of September 30, 2025, borrowings under the Facility totaled approximately $1.1 billion and the undrawn availability under the Facility was $225.0 million. Final maturity of the Facility is December 31, 2029. In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Company’s production assets in Ghana and Equatorial Guinea.

Interest on the Facility is the aggregate of the applicable margin (4.00% to 5.50%, 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. 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.

The Facility provides a revolving credit and letter of credit facility. As of September 30, 2025, we had no letters of credit issued under the Facility.

When our debt cover ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our debt cover ratio was 2.54x, partially due to pre-production operating costs associated with the GTA Phase 1 project. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance through 2025.

In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes this covenant less restrictive for the two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business

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operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations.

We were in compliance with the financial covenants contained in the Facility as of September 30, 2025 (the most recent assessment date) including the liquidity test undertaken covering the Company’s 7.750% Senior Notes due 2027 which was carried out alongside the RBL re-determination in September 2025. The Facility 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 fees.

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 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible 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 Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of $400.0 million of the 7.125% Senior Notes pursuant to the Company’s cash tender offers for portions of the 7.125% Senior Notes, the 7.750% Senior Notes, and the 7.500% Senior Notes announced on September 9, 2024 (the “Tender Offers”). The 7.125% Senior Notes contain customary cross default provisions. In October 2025, we used proceeds from funding of the first tranche under the GoA Term Loan Facility to complete the partial redemption of an additional aggregate principal amount of $150.0 million of the 7.125% Senior Notes.

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 7.125% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible 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 Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of $50.0 million of the 7.750% Senior Notes pursuant to the Tender Offers. 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 7.125% Senior Notes, the 7.750% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible 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 Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125% Senior Notes, the 7.750% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of approximately $49.7 million of the 7.500% Senior Notes pursuant to the Tender Offers. The 7.500% Senior Notes contain customary cross default provisions.

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8.750% Senior Notes due 2031

In September 2024, the Company issued $500.0 million of 8.750% Senior Notes (the “8.750% Senior Notes”) and received net proceeds of approximately $494.9 million after deducting fees.

The 8.750% Senior Notes mature on October 1, 2031. Interest is payable in arrears each April 1 and October 1, commencing on April 1, 2025. The 8.750% 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 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 3.125% Convertible 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 8.750% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company’s Gulf of America assets and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 3.125% Convertible Senior Notes. The 8.750% Senior Notes contain customary cross default provisions.

3.125% Convertible Senior Notes due 2030

In March 2024, the Company issued $400.0 million of 3.125% Convertible Senior Notes (the “3.125% Convertible Senior Notes”) and received net proceeds of $390.4 million after deducting fees.

The 3.125% Convertible Senior Notes mature on March 15, 2030, unless earlier converted, redeemed or repurchased. Interest is payable in arrears each March 15 and September 15, commencing September 15, 2024. The 3.125% Convertible 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 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 8.750% 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, to the extent of the value of the assets securing such indebtedness). The 3.125% Convertible Senior Notes are guaranteed on a senior, unsecured basis by certain of our existing subsidiaries that guarantee on a senior basis the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 8.750% Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries. The 3.125% Convertible Senior Notes are guaranteed on a subordinated, unsecured basis by certain of our existing subsidiaries that borrow under or guarantee the Facility and guarantee on a subordinated basis the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 8.750% Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries.

The 3.125% Convertible Senior Notes indenture contains customary terms and covenants.

The Company recorded the 3.125% Convertible Senior Notes, including the debt itself and all embedded derivatives, at cost less debt issuance costs of $9.6 million and has presented the 3.125% Convertible Senior Notes as a single financial instrument in Long-term debt, net in our consolidated balance sheet. No portion of the embedded derivatives required bifurcation from the host debt contract. As of September 30, 2025, the effective annual interest rate on the 3.125% Convertible Senior Notes is approximately 3.70%, including amortization of debt issuance costs.

The conversion rate for the 3.125% Convertible Senior Notes is initially 142.4501 shares of our common stock per $1,000 principal amount of 3.125% Convertible Senior Notes (which is the equivalent to an initial conversion price of approximately $7.02 per share of our common stock), subject to adjustments. As of September 30, 2025, no shares have been converted.

Capped Call Transactions

In connection with the issuance of the 3.125% Convertible Senior Notes, the Company used $49.8 million of the net proceeds from the issuance of the 3.125% Convertible Senior Notes to enter into capped call transactions (the “Capped Call Transactions”). The Capped Call Transactions are generally expected to reduce potential dilution to holders of our common stock upon any conversion of the 3.125% Convertible Senior Notes and/or offset any cash payments that we are required to make in excess of the principal amount of any 3.125% Convertible Senior Notes that are converted, as the case may be, with such reduction and/or offset subject to a cap.

The Capped Call Transactions qualify for a derivative scope exception as they are indexed to our common stock and are not required to be accounted for as a separate derivative. Consequently, the Capped Call Transactions have been included as a net reduction to additional-paid-in-capital within stockholders’ equity in our consolidated balance sheet and do not require subsequent remeasurement.

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GoA Term Loan Facility

On September 24, 2025, the Company entered into a senior secured term loan credit agreement secured by first priority liens on all of the Company’s Gulf of America assets (as defined in the Credit Agreement). The GoA Term Loan Facility is structured in two tranches, with the first tranche consisting of a four-year term loan in an aggregate principal amount of $150.0 million, which was funded on October 1, 2025, and a second tranche comprising commitments to lend up to an additional $100.0 million, available for drawing until April 1, 2026. On October 1, 2025, we received net proceeds of $147.2 million from funding of the first tranche after deducting fees and other expenses. On October 6, 2025, the net proceeds were used, together with cash on hand, to fund the redemption of a portion of the 7.125% Senior Notes due 2026 totaling $150.0 million in aggregate. The proceeds from any additional borrowings on the GoA Term Loan Facility is expected to be used to fund the redemption or repayment of the Company’s Senior Notes.

Interest on outstanding loans under the GoA Term Loan Facility is payable quarterly in arrears at a rate per annum equal to 3.75% plus the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published. The GoA Term Loan Facility matures in 2029, with principal payments beginning June 30, 2026.

The GoA Term Loan Facility contains customary affirmative and negative covenants, including covenants that affect our ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or capital expenditures, among other things. The GoA Term Loan Facility requires the Company to maintain certain financial covenants including:

•the GoA field life coverage ratio (as defined in the glossary), not less than 1.50x; and

•the GoA net leverage ratio (as defined in the glossary), not more than 3.50x and

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

Principal Debt Repayments

At September 30, 2025, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:


	Payments Due by Year
	Total		2025(2)		2026		2027		2028		2029		Thereafter
	(In thousands)
Principal debt repayments(1)	$	3,025,274	$	—	$	250,000	$	569,086	$	796,761	$	509,427	$	900,000

__________________________________

(1)Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as of September 30, 2025 are based on our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

(2)Represents payments for the period October 1, 2025 through December 31, 2025.

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Interest and other financing costs, net

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In thousands)
Interest expense	$	58,393	$	54,530	$	170,064	$	162,467
Amortization—deferred financing costs	1,889		2,159		5,662		6,814
Debt modifications and extinguishments	—		2,263		—		24,794
Capitalized interest	(4,411)		(42,081)		(12,921)		(126,007)
Deferred interest	1,079		2,571		(714)		(411)
Interest income	(7,390)		(5,710)		(22,643)		(16,584)
Other, net	8,359		8,380		25,147		24,766
Interest and other financing costs, net	$	57,919	$	22,112	$	164,595	$	75,839

Cash payments for interest totaled $28.6 million and $42.2 million for the three months ended September 30, 2025 and 2024, respectively, and $134.4 million and $132.7 million for the nine months ended September 30, 2025 and 2024, respectively. Capitalized interest totaled $4.4 million and $42.1 million for the three months ended September 30, 2025 and 2024, respectively, and $12.9 million and $126.0 million for the nine months ended September 30, 2025 and 2024, respectively. The decrease in capitalized interest during the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024 is primarily due to the achievement of first gas production on the GTA Phase 1 project on December 31, 2024, after which we no longer capitalize interest on the project.

7. Derivative Financial Instruments

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

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

Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of September 30, 2025. 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)		Swap		Put		Floor		Ceiling
2025:
Oct - Dec	Two-way collars	Dated Brent	2,000	$	1.35	$	—	$	—	$	60.00	$	74.94
Oct - Dec	Three-way collars	Dated Brent	500	1.13		—		55.00		70.00		85.00
2026:
Jan - Jun	Two-way collars	Dated Brent	1,000	1.55		—		—		60.00		74.75
Jan - Dec	Three-way collars	Dated Brent	2,000	—		—		50.00		60.00		75.51
Jan - Jun	Swaps(1)	Dated Brent	1,000	—		72.90		—		—		80.00
Jan - Dec	Swaps(1)	Dated Brent	1,000	—		72.46		—		—		80.00
Jan - Dec	Swaps(1)	Dated Brent	2,000	—		69.70		55.00		—		—
Jan - Dec	Swaps(1)	NYMEX WTI	1,500	—		64.83		50.00		—		—

__________________________________

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(1)Includes option contracts sold to counterparties to enhance Swaps.

Interest Rate Derivative Contracts

The following table summarizes our open interest rate swaps whereby we pay a fixed rate of interest and the counterparty pays a variable SOFR-based rate as of September 30, 2025:

Weighted Average

Term

Type of Contract

Floating Rate

Notional

Fixed Rate

(In Thousands)

Oct - Dec 2025

Swap

1-Month TERM SOFR

500,000

3.645

The following tables disclose the Company’s derivative instruments as of September 30, 2025 and December 31, 2024, and gain/(loss) from derivatives during the three and nine months ended September 30, 2025 and 2024, respectively:


		Estimated Fair Value
		Asset (Liability)
Type of Contract	Balance Sheet Location	September 30, 2025		December 31, 2024
		(In thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Commodity	Derivatives assets—current	$	18,859	$	6,714
Provisional oil sales	Receivables: Oil and gas sales	999		2,242
Interest rate	Derivatives assets—current	178		2,202
Commodity	Derivatives assets—long-term	3,025		512
Derivative liabilities:
Commodity	Derivatives liabilities—current	(3,239)		—


Commodity	Derivatives liabilities—long-term	(278)		—

Total derivatives not designated as hedging instruments		$	19,544	$	11,670


		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)	2025		2024		2025		2024
		(In thousands)
Derivatives not designated as hedging instruments:
Provisional oil sales	Oil and gas revenue	$	(964)	$	(4,674)	$	(8,571)	$	(4,810)
Commodity	Derivatives, net	3,646		15,254		18,480		(5,716)
Interest rate	Interest expense	110		(1,282)		766		(1,282)
Total derivatives not designated as hedging instruments		$	2,792	$	9,298	$	10,675	$	(11,808)

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, 2025 and December 31, 2024, 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.

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8. 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, 2025 and December 31, 2024, 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, 2025
Assets:
Commodity derivatives	$	—	$	21,884	$	—	$	21,884
Provisional oil sales	—		999		—		999
Interest rate derivatives	—		178		—		178
Decommissioning trust fund:
Debt securities	—		23,478		—		23,478
Liabilities:
Commodity derivatives	—		(3,517)		—		(3,517)


Total	$	—	$	43,022	$	—	$	43,022
December 31, 2024
Assets:
Commodity derivatives	$	—	$	7,226	$	—	$	7,226
Provisional oil sales	—		2,242		—		2,242
Interest rate derivatives	—		2,202		—		2,202
Decommissioning trust fund:
Debt securities	—		10,653		—		10,653




Total	$	—	$	22,323	$	—	$	22,323

The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil and gas 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 swaps, crude oil collars, put options and call options for notional barrels of oil at fixed Dated Brent and 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 7 — 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.

Interest Rate Derivatives

Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable SOFR-based rate. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) SOFR yield curves provided by independent third parties and corroborated with forward active market-quoted SOFR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.

Decommissioning Trust Fund

In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. Each partner will contribute annually to the trust in proportion to its respective paying interest of the estimated future dismantlement, abandonment and restoration costs associated with the decommissioning of the Jubilee Field. Contributions to the trust are used by the trustee of the fund, the Bank of Ghana, to purchase and sell authorized securities at the direction of the Jubilee unit partners.

As of September 30, 2025, the investments held in the decommissioning trust fund are US Treasury debt securities. We have classified the investments as trading securities and recorded such investments at fair market value as a long-term investment in our consolidated balance sheet using observable inputs including Kosmos’ share of the fund and broker/dealer bid/ask prices of the investments held by the fund at September 30, 2025. Contributions made to the decommissioning trust are reported as investing activities in our consolidated cash flows. All realized and unrealized gains and losses resulting from the sales and maturities or changes in fair value of the securities are recognized in Other income, net. During the nine months ended September 30, 2025, we contributed $11.5 million to the decommissioning trust fund.

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The following table summarizes Kosmos’ portion of the investment activity in debt securities held by the decommissioning trust during the three and nine months ended September 30, 2025 and 2024:


	Three Months Ended September 30,						Nine Months Ended September 30,

Type of Security	Purchases		Net Proceeds (1)		Unrealized Gain (Loss)		Purchases		Net Proceeds (1)		Unrealized Gain (Loss)
2025
Debt securities	$	245	$	—	$	43	$	12,651	$	—	$	174
Cash and cash equivalents	—		(3)		—		—		(748)		—
Other(1)	—		(17)		—		—		149		—
Total	$	245	$	(20)	$	43	$	12,651	$	(599)	$	174
2024
Debt securities	$	—	$	—	$	—	$	—	$	—	$	—
Cash and cash equivalents	—		—		—		—		—		—
Other(1)	—		—		—		—		—		—
Total	$	—	$	—	$	—	$	—	$	—	$	—

(1) Represents net receivables relating to interest.

The following table presents the costs and fair values of investments in debt securities held in the decommissioning trust fund according to the contractual maturities at September 30, 2025 and December 31, 2024:


	September 30, 2025				December 31, 2024
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
	(In thousands)
Less than 5 years	$	23,359	$	23,478	$	10,708	$	10,653
5 years to 10 years	—		—		—		—
Due after 10 years	—		—		—		—
Total	$	23,359	$	23,478	$	10,708	$	10,653

Debt

The following table presents the carrying values and fair values at September 30, 2025 and December 31, 2024:


	September 30, 2025				December 31, 2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In thousands)
7.125% Senior Notes	$	249,716	$	249,448	$	249,315	$	246,565
7.750% Senior Notes	348,540		341,022		347,910		339,927
7.500% Senior Notes	398,232		352,978		397,672		379,404
8.750% Senior Notes	495,418		386,875		494,997		470,965
3.125% Convertible Senior Notes	392,718		254,000		391,603		332,792


Facility	1,125,000		1,125,000		900,000		900,000
Total	$	3,009,624	$	2,709,323	$	2,781,497	$	2,669,653

The carrying values of our 7.125% Senior Notes, 7.750% Senior Notes, 7.500% Senior Notes, 8.750% Senior Notes and 3.125% Convertible Senior Notes represent the principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes, 7.750% Senior Notes, 7.500% Senior Notes, 8.750% Senior Notes and 3.125% Convertible Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility

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approximates 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, 2025 and 2024, the Company did not recognize impairment of proved oil and gas properties. If we experience material declines in oil pricing expectations in the future, significant increases in our estimated future expenditures or a significant decrease in our estimated production profile, our long-lived assets could be at risk of impairment.

9. 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 $5.3 million and $10.0 million during the three months ended September 30, 2025 and 2024, respectively, and $21.0 million and $27.8 million during the nine months ended September 30, 2025 and 2024, respectively. The total tax benefit for the three months ended September 30, 2025 and 2024 was $1.3 million and $1.7 million, respectively, and $3.9 million and $4.5 million during the nine months ended September 30, 2025 and 2024, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of nil and $(0.1) million for the three months ended September 30, 2025 and 2024, respectively, and $3.4 million and $(9.6) million during the nine months ended September 30, 2025 and 2024, respectively. The fair value of awards vested during the three months ended September 30, 2025 and 2024 was $0.1 million and $0.4 million, respectively, and $19.8 million and $82.0 million during the nine months ended September 30, 2025 and 2024, 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.

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 $3.05 to $13.06 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 58.0% 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 4.2%.

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The following table reflects the outstanding restricted stock units as of September 30, 2025:


		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, 2024	4,753	$	6.36	8,766	$	9.07
Granted(1)	3,193	3.24		3,938	4.93
Forfeited(1)	(423)	5.43		(537)	7.62
Vested	(2,332)	6.07		(4,027)	6.97
Outstanding at September 30, 2025	5,191	4.64		8,140	8.43

__________________________________

(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, 2025, total equity-based compensation to be recognized on unvested restricted stock units is $25.4 million over a weighted average period of 1.66 years. At September 30, 2025, the Company had approximately 4.2 million shares that remain available for issuance under the LTIP.

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10. 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,
	2025		2024		2025		2024
	(In thousands)
United States	$	(81,858)	$	(35,934)	$	(186,319)	$	(110,976)
Foreign	(24,614)		142,486		(77,944)		494,621
Income before income taxes	$	(106,472)	$	106,552	$	(264,263)	$	383,645

For the three months ended, September 30, 2025 and 2024, our effective tax rate was (17)% and 58%, respectively. For the nine months ended September 30, 2025 and 2024, our effective tax rate was (22)% and 49%, respectively. For the three and nine months ended September 30, 2025 and 2024, 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.

In July 2025, new U.S tax legislation was signed into law in the United States known as the "One Big Beautiful Bill Act" or "OBBBA". The legislation includes a broad range of U.S. corporate tax reform provisions affecting businesses across numerous industries. The necessary adjustments have been reflected for the nine months ended September 30, 2025. Based on our evaluation, we have determined that the impact of OBBBA is not material to the Company’s financial position or results.

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11. Net Income (Loss) Per Share

The following table is a reconciliation between net income (loss) and the amounts used to compute basic and diluted net income (loss) per share and the weighted average shares outstanding used to compute basic and diluted net income (loss) per share. Potentially dilutive securities include shares issuable upon conversion of our 3.125% Convertible Senior Notes using the if-converted method and restricted stock units awards under our equity-based compensation plan.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2025		2024		2025		2024
	(In thousands, except per share data)
Numerator:
Net income (loss) allocable to common stockholders	$	(124,299)	$	44,974	$	(322,645)	$	196,430




Denominator:
Weighted average number of shares outstanding:
Basic	478,254		471,816		477,344		470,491
Restricted stock units(1)	—		7,374		—		8,210
Shares issuable assuming conversion of 3.125% Convertible Senior Notes(2)	—		—		—		—
Diluted	478,254		479,190		477,344		478,701
Net income (loss) per share:
Basic	$	(0.26)	$	0.10	$	(0.68)	$	0.42
Diluted	$	(0.26)	$	0.09	$	(0.68)	$	0.41

__________________________________

(1)We excluded restricted stock units of 5.4 million and 3.1 million for the three months ended September 30, 2025 and 2024, respectively, and 5.7 million and 2.8 million for the nine months ended September 30, 2025 and 2024, respectively from the computations of diluted net income (loss) per share because the effect would have been anti-dilutive.

(2)Represents the dilutive impact for the Company’s 3.125% Convertible Senior Notes due 2030. As of September 30, 2025, the if-converted value is less than the outstanding principal of the 3.125% Convertible Senior Notes and therefore anti-dilutive. The 3.125% Convertible Senior Notes are subject to a capped call arrangement that potentially reduces the dilutive effect. Any potential impact of the capped call arrangement is excluded from this table as any proceeds under the capped call arrangement are considered anti-dilutive.

12. 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 that the likelihood of an unfavorable outcome having a material impact is neither reasonably possible nor probable of occurring.

As of September 30, 2025, we have a commitment to drill one development well in Equatorial Guinea.

In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total remaining commitment to be approximately $126.1 million as of September 30, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated 11 year period.

Performance Obligations

As of September 30, 2025 and December 31, 2024, the Company had performance and supplemental bonds totaling $153.4 million and $169.4 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 Gulf of America fields.

We have a commitment to our buyer under the Tortue Phase 1 SPA, BP Gas Marketing Limited, to deliver our proportionate share of a minimum annual contract quantity of LNG of 127,951,000 MMBtu, which is equivalent to approximately 2.45 million tonnes per annum, subject to certain downward adjustments by the sellers. Under certain circumstances, in the event the annual quantities provided are lower than the minimum annual contract quantity, Kosmos may be obligated to credit or pay a portion of the Contract Price to BP Gas Marketing Limited for the shortfall volumes.

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13. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:


	September 30, 2025		December 31, 2024
	(In thousands)
Accrued liabilities:
Exploration, development and production	$	59,042	$	78,163
Revenue payable	57,523		18,909
General and administrative expenses	4,814		39,071
Interest	93,909		47,228
Income taxes	19,647		52,262
Taxes other than income	1,334		1,222
Derivatives	587		844
Other	14,454		7,255
	$	251,310	$	244,954

__________________________________

The increase in revenue payable during the nine months ended September 30, 2025 is primarily related to timing of a Jubilee lifting and receipt of related proceeds.

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, 2025:


	September 30, 2025
	(In thousands)
Asset retirement obligations:
Beginning asset retirement obligations	$	407,011
Liabilities incurred during period	1,732
Liabilities settled during period	(2,014)
Revisions in estimated retirement obligations	(33,863)
Accretion expense	27,694
Ending asset retirement obligations	$	400,560

The revisions in estimated retirement obligations during the nine months ended September 30, 2025 are related to changes in the estimated timing of the decommissioning operations.

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14. 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, 2025, the Company had operations in four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the Gulf of America. The Company’s Chief Operating Decision Maker (“CODM”) is the Chief Executive Officer, who makes decisions about allocating resources and assessing performance for the entire company. To assess performance of the reporting segments, the CODM regularly reviews oil and gas revenues, oil and gas production costs, exploration expenses and capital expenditures by reporting segment in deciding how to allocate resources and in assessing performance. 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		Gulf of America		Corporate & Other		Eliminations		Total
	(In thousands)
Three months ended September 30, 2025
Revenues and other income:
Oil and gas revenue	$	141,146	$	41,777	$	39,343	$	88,693	$	—	$	—	$	310,959

Other income, net	269		—		—		19		8,683		(8,701)		270
Total revenues and other income	141,415		41,777		39,343		88,712		8,683		(8,701)		311,229
Costs and expenses:
Oil and gas production	22,871		33,700		59,401		31,724		—		—		147,696
Exploration expenses	—		(211)		1,944		53,134		81		—		54,948
General and administrative	2,771		816		1,930		1,480		18,237		(12,348)		12,886
Depletion, depreciation and amortization	43,180		19,658		21,728		56,812		136		—		141,514

Interest and other financing costs, net(1)	13,723		(38)		5,814		(2,187)		40,607		—		57,919
Derivatives, net	—		—		—		—		(3,646)		—		(3,646)
Other expenses, net	(2,135)		6,132		421		(1,821)		141		3,646		6,384
Total costs and expenses	80,410		60,057		91,238		139,142		55,556		(8,702)		417,701
Income (loss) before income taxes	61,005		(18,280)		(51,895)		(50,430)		(46,873)		1		(106,472)
Income tax expense	22,103		(3,933)		—		—		(343)		—		17,827
Net income (loss)	$	38,902	$	(14,347)	$	(51,895)	$	(50,430)	$	(46,530)	$	1	$	(124,299)

Consolidated capital expenditures, net	$	23,561	$	6,099	$	6,761	$	30,026	$	889	$	—	$	67,336

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	Ghana		Equatorial Guinea		Mauritania/Senegal		Gulf of America		Corporate & Other		Eliminations		Total
	(In thousands)
Nine months ended September 30, 2025
Revenues and other income:
Oil and gas revenue	$	497,104	$	140,774	$	62,279	$	293,572	$	—	$	—	$	993,729
Gain on sale of assets	—		—		—		600		—		—		600
Other income, net	768		—		—		728		69,352		(69,999)		849
Total revenues and other income	497,872		140,774		62,279		294,900		69,352		(69,999)		995,178
Costs and expenses:
Oil and gas production	159,539		90,635		186,643		121,305		—		—		558,122
Exploration expenses	70		1,258		5,681		60,279		1,398		—		68,686
General and administrative	8,959		3,787		7,033		9,933		116,983		(88,480)		58,215
Depletion, depreciation and amortization	131,620		62,226		37,322		181,851		430		—		413,449

Interest and other financing costs, net(1)	38,107		(167)		10,216		(6,348)		122,787		—		164,595
Derivatives, net	—		—		—		—		(18,480)		—		(18,480)
Other expenses, net	(8,022)		815		1,569		1,442		570		18,480		14,854
Total costs and expenses	330,273		158,554		248,464		368,462		223,688		(70,000)		1,259,441
Income (loss) before income taxes	167,599		(17,780)		(186,185)		(73,562)		(154,336)		1		(264,263)
Income tax expense (benefit)	60,772		(3,042)		—		(14)		666		—		58,382
Net income (loss)	$	106,827	$	(14,738)	$	(186,185)	$	(73,548)	$	(155,002)	$	1	$	(322,645)

Consolidated capital expenditures, net	$	80,257	$	8,657	$	68,879	$	79,539	$	2,299	$	—	$	239,631

As of September 30, 2025
Property and equipment, net	$	946,479	$	435,986	$	2,092,629	$	716,712	$	16,729	$	—	$	4,208,535
Total assets	$	3,341,717	$	2,477,126	$	3,405,756	$	2,714,156	$	26,831,583	$	(33,680,597)	$	5,089,741

______________________________________

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

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	Ghana		Equatorial Guinea		Mauritania/Senegal		Gulf of America		Corporate & Other		Eliminations		Total
	(In thousands)
Three months ended September 30, 2024
Revenues and other income:
Oil and gas revenue	$	233,348	$	70,970	$	—	$	103,476	$	—	$	—	$	407,794

Other income, net	—		—		—		543		23,160		(23,666)		37
Total revenues and other income	233,348		70,970		—		104,019		23,160		(23,666)		407,831
Costs and expenses:
Oil and gas production	26,955		37,237		39,685		29,594		—		—		133,471
Exploration expenses	1,413		1,881		4,633		5,380		1,390		—		14,697
General and administrative	3,004		1,282		3,301		3,725		50,905		(38,919)		23,298
Depletion, depreciation and amortization	47,919		15,003		233		56,496		1,077		—		120,728

Interest and other financing costs, net(1)	13,408		(810)		(37,043)		(2,309)		48,866		—		22,112
Derivatives, net	—		—		—		—		(15,254)		—		(15,254)
Other expenses, net	(15,166)		157		881		1,040		62		15,253		2,227
Total costs and expenses	77,533		54,750		11,690		93,926		87,046		(23,666)		301,279
Income (loss) before income taxes	155,815		16,220		(11,690)		10,093		(63,886)		—		106,552
Income tax expense (benefit)	55,350		6,455		—		564		(791)		—		61,578
Net income (loss)	$	100,465	$	9,765	$	(11,690)	$	9,529	$	(63,095)	$	—	$	44,974

Consolidated capital expenditures, net	$	16,583	$	51,056	$	75,997	$	63,820	$	2,552	$	—	$	210,008

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	Ghana		Equatorial Guinea		Mauritania/Senegal		Gulf of America		Corporate & Other		Eliminations		Total
	(In thousands)
Nine months ended September 30, 2024
Revenues and other income:
Oil and gas revenue	$	821,880	$	188,917	$	—	$	267,000	$	—	$	—	$	1,277,797

Other income, net	1		—		—		2,028		123,674		(125,594)		109
Total revenues and other income	821,881		188,917		—		269,028		123,674		(125,594)		1,277,906
Costs and expenses:
Oil and gas production	123,250		97,942		57,851		98,779		—		—		377,822
Exploration expenses	3,665		5,263		13,880		13,392		3,792		—		39,992
General and administrative	9,882		4,027		8,567		15,097		159,028		(119,877)		76,724
Depletion, depreciation and amortization	144,609		38,895		684		125,765		1,797		—		311,750

Interest and other financing costs, net(1)	39,204		(2,406)		(107,808)		(10,702)		157,551		—		75,839
Derivatives, net	—		—		—		—		5,716		—		5,716
Other expenses, net	5,817		(2,197)		6,111		2,358		45		(5,716)		6,418
Total costs and expenses	326,427		141,524		(20,715)		244,689		327,929		(125,593)		894,261
Income (loss) before income taxes	495,454		47,393		20,715		24,339		(204,255)		(1)		383,645
Income tax expense (benefit)	170,060		19,019		—		644		(2,508)		—		187,215
Net income (loss)	$	325,394	$	28,374	$	20,715	$	23,695	$	(201,747)	$	(1)	$	196,430

Consolidated capital expenditures, net	$	128,247	$	129,296	$	287,193	$	161,555	$	5,360	$	—	$	711,652

As of September 30, 2024
Property and equipment, net	$	1,031,498	$	523,312	$	2,177,621	$	945,138	$	16,866	$	—	$	4,694,435
Total assets	$	3,514,342	$	2,310,092	$	3,209,803	$	4,074,383	$	25,174,519	$	(32,812,193)	$	5,470,946

______________________________________

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


	Nine Months Ended September 30,
	2025		2024
	(In thousands)
Consolidated capital expenditures:
Consolidated Statements of Cash Flows - Investing activities:
Oil and gas assets	$	244,133	$	772,238


Adjustments:
Changes in capital accruals	(19,642)		25,108
Exploration expense, excluding unsuccessful well costs and leasehold impairments(1)	17,314		36,120
Capitalized interest	(12,920)		(126,007)
Other	10,746		4,193
Total consolidated capital expenditures, net	$	239,631	$	711,652

______________________________________

(1)Costs related to unsuccessful exploratory wells and leaseholds that are subsequently written off to Exploration expense are included in oil and gas assets when incurred.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended December 31, 2024, 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

Recent Developments

Ghana

During the third quarter of 2025, Ghana production averaged approximately 93,600 Boepd gross (31,300 Boepd net).

Jubilee development drilling progressed in the third quarter of 2025 bringing one producer well successfully online in July 2025. After undergoing scheduled maintenance, the rig is back in the field and currently drilling an additional producer well in the Jubilee Field in the fourth quarter of 2025 to be followed by drilling four planned producer wells and an additional water injector well in 2026.

In June 2025, the Jubilee and TEN partnerships entered into a Memorandum of Understanding with the Government of Ghana to extend to 2040 the WCTP and the DT licenses, which cover the Jubilee and TEN fields offshore Ghana. The partnership has prepared amendments to the respective Petroleum Agreements, a Jubilee Plan of Development Amendment, an amendment to the Jubilee Gas Sales Agreement covering future gas sales from the Jubilee Field, as well as the other necessary documents for submission to the Government of Ghana for parliamentary approval.

Gulf of America

Production from the Gulf of America averaged approximately 16,600 Boepd net (~84% oil) for the third quarter of 2025.

On Tiberius, Kosmos (operator, 50% working interest) continues to progress the development plan with our partner Occidental Petroleum Corporation (“Oxy”) (50% working interest). A production handling agreement for the Oxy-operated Lucius platform was signed in the third quarter of 2025. Final investment decision and a farm down to reduce Kosmos’ working interest is expected in 2026.

In July 2024, we announced start-up of oil production from the first phase of the Winterfell development in the Green Canyon area of the Gulf of America (25% working interest). In October 2024, shortly after startup of the third well, production at the field was curtailed due to sand production from the third well. Production from the first two wells was restored in December 2024. Remediation work on Winterfell-3 was performed in the first quarter of 2025, however, it was unsuccessful. Winterfell-3 was temporarily plugged and abandoned during the first quarter of 2025 while the partnership evaluates options to restore production from the Winterfell-3 fault block. During the second quarter of 2025, the partnership drilled the Winterfell-4 well to test a separate fault block and define the eastern extent of the Winterfell reservoir area. The Wintefell-4 well was abandoned in September 2025 by the operator due to challenges during completion operations arising from the collapse of the production casing. As a result, all associated drilling and completion capitalized costs of approximately $51.1 million related to

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Winterfell-4 have been written off in the third quarter of 2025. The partnership will continue to review alternative options to access those resources with near-term activity in 2026 focused on restoring production from the Winterfell-3 fault block.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 17,700 Bopd gross (6,200 Bopd net) in the third quarter of 2025, impacted by multiple subsea multiphase flow pump (MPP) mechanical failures at Ceiba during the second quarter of 2025. The first pump was repaired ahead of schedule early in the fourth quarter of 2025, and the second pump is now also expected online in the fourth quarter followed by the third pump in the first quarter of 2026.

In October 2025, we received approval from the Ministry of Hydrocarbons and Mining Development for a twelve month extension to December 2026 for the current exploration phase of Block EG-24.

Mauritania and Senegal

Greater Tortue Ahmeyim Project

Production in Mauritania and Senegal averaged approximately 46,900 Boepd gross (11,400 Boepd net) in the third quarter of 2025, as production from the GTA field continued to ramp up.

The Greater Tortue Ahmeyim (GTA) liquified natural gas (LNG) project achieved first gas production from the subsea system to the FPSO on December 31, 2024. First LNG was achieved in February 2025 and the first gross LNG cargo was successfully exported in April 2025 with 13.5 gross cargoes lifted through October 2025, along with the first gross condensate cargo. Additionally, the Gimi FLNG vessel Commercial Operations Date was achieved in the second quarter of 2025 with successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum.

Sao Tome and Principe

In May 2025, we received approval for a twelve month extension to May 2026 for the current exploration phase for Block 5 offshore Sao Tome and Principe.

Corporate

On September 24, 2025, the Company entered into a senior secured term loan credit agreement secured by first priority liens on all of the Company’s Gulf of America assets (as defined in the Credit Agreement). The GoA Term Loan Facility is structured in two tranches, with the first tranche consisting of a four-year term loan in an aggregate principal amount of $150.0 million, which was funded on October 1, 2025, and a second tranche comprising commitments to lend up to an additional $100.0 million, available for drawing until April 1, 2026. On October 1, 2025, we received net proceeds of $147.2 million from funding of the first tranche after deducting fees and other expenses. On October 6, 2025, the net proceeds were used, together with cash on hand, to fund the redemption of a portion of the 7.125% Senior Notes due 2026 totaling $150 million in aggregate. The GoA Term Loan Facility matures in 2029, with principal payments beginning June 30, 2026.

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Results of Operations

All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Certain operating results and statistics for the three and nine months ended September 30, 2025 and 2024 are included in the following tables:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
	(In thousands, except per volume data)
Sales volumes:
Oil (MBbl)	3,799			5,135			12,822			15,234
Gas (MMcf)	9,712			3,554			21,004			11,991
NGL (MBbl)	97			84			301			232
Total (MBoe)	5,515			5,811			16,624			17,465
Total (Boepd)	59,942			63,167			60,893			63,739

Revenues:
Oil sales	$	255,661		$	393,555		$	880,584		$	1,230,772
Gas sales	53,761			12,586			107,439			42,218
NGL sales	1,537			1,653			5,706			4,807
Total oil and gas revenue	$	310,959		$	407,794		$	993,729		$	1,277,797

Average oil sales price per Bbl	$	67.30		$	76.64		$	68.68		$	80.79
Average gas sales price per Mcf	5.54			3.54			5.12			3.52
Average NGL sales price per Bbl	15.85			19.68			18.96			20.72
Average total sales price per Boe	$	56.39		$	70.18		$	59.78		$	73.16

Costs:
Oil and gas production, excluding workovers	$	143,737		$	132,736		$	538,670		$	345,902
Oil and gas production, workovers	3,959			735			19,452			31,920
Total oil and gas production costs	$	147,696	(1)	$	133,471	(2)	$	558,122	(1)	$	377,822	(2)

Depletion, depreciation and amortization	$	141,514		$	120,728		$	413,449		$	311,750

Average cost per Boe:
Oil and gas production, excluding workovers	$	26.06		$	22.84		$	32.40		$	19.81
Oil and gas production, workovers	0.72			0.13			1.17			1.83
Total oil and gas production costs	$	26.78	(1)	$	22.97	(2)	$	33.57	(1)	$	21.64	(2)

Depletion, depreciation and amortization	25.66			20.77			24.87			17.85
Total	$	52.44		$	43.74		$	58.44		$	39.49

______________________________________

(1)Includes $59.4 million and $186.6 million for the three and nine months ended September 30, 2025, respectively, related to the LNG production at the GTA Phase 1 project in Mauritania and Senegal. All gas sales in Mauritania and Senegal are LNG sales. First LNG was achieved in February 2025 and the first LNG cargo was successfully completed in April 2025.

(2)Includes $39.7 million and $57.9 million for the three and nine months ended September 30, 2024, respectively, of oil and gas production costs related to the LNG production at the GTA Phase 1 project in Mauritania and Senegal.

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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, 2025:


	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	—	—	—	—	—	—	3	1.16
TEN	—	—	—	—	—	—	5	1.02
Equatorial Guinea
Block G	—	—	—	—	—	—	1	0.40
Gulf of America


Tiberius	—	—	—	—	1	0.50	—	—
Mauritania / Senegal
Greater Tortue Ahmeyim	—	—	—	—	1	0.27	—	—
Senegal Cayar Profond	—	—	—	—	3	2.70	—	—
Total	—	—	—	—	5	3.47	9	2.58

______________________________________

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, 2025 compared to three months ended September 30, 2024


	Three Months Ended
	September 30,				Increase
	2025		2024		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	310,959	$	407,794	$	(96,835)

Other income, net	270		37		233
Total revenues and other income	311,229		407,831		(96,602)
Costs and expenses:
Oil and gas production	147,696		133,471		14,225
Exploration expenses	54,948		14,697		40,251
General and administrative	12,886		23,298		(10,412)
Depletion, depreciation and amortization	141,514		120,728		20,786

Interest and other financing costs, net	57,919		22,112		35,807
Derivatives, net	(3,646)		(15,254)		11,608
Other expenses, net	6,384		2,227		4,157
Total costs and expenses	417,701		301,279		116,422
Income (loss) before income taxes	(106,472)		106,552		(213,024)
Income tax expense	17,827		61,578		(43,751)
Net income (loss)	$	(124,299)	$	44,974	$	(169,273)

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Oil and gas revenue. Oil and gas revenue decreased by $96.8 million during the three months ended September 30, 2025 as compared to the three months ended September 30, 2024 primarily as a result of lower average realized oil and gas prices and lower production and sales volumes at Jubilee and Ceiba offset by an increase in production and sales volumes in Mauritania & Senegal with first LNG cargo sales beginning in 2025. We sold 5,515 MBoe at an average realized price per barrel equivalent of $56.39 during the three months ended September 30, 2025 and 5,811 MBoe at an average realized price per barrel equivalent of $70.18 during the three months ended September 30, 2024.

Oil and gas production. Oil and gas production costs increased by $14.2 million during the three months ended September 30, 2025 as compared to the three months ended September 30, 2024 primarily as a result of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal offset by lower operating costs at Jubilee and Ceiba.

Exploration expenses. Exploration expenses increased by $40.3 million during the three months ended September 30, 2025, as compared to the three months ended September 30, 2024 primarily as a result of approximately $51.1 million of exploration expense for the three months ended September 30, 2025 related to the Winterfell-4 step out well which was plugged and abandoned during the third quarter of 2025 offset by decreased geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.

General and administrative expenses. General and administrative expenses decreased during the three months ended September 30, 2025, as compared to the three months ended September 30, 2024 primarily as a result of a reduction in employee compensation during 2025.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased by $20.8 million during the three months ended September 30, 2025, as compared with the three months ended September 30, 2024 primarily as a result higher depletion rates per boe across our portfolio owing to increased cost basis related to the respective development activities in 2024 partially offset by lower sales volumes across our portfolio.

Interest and other financing costs, net. Interest and other financing costs, net increased by $35.8 million during the three months ended September 30, 2025, as compared to the three months ended September 30, 2024 primarily as a result of decreased capitalized interest related to the GTA Phase 1 project post first gas production in December 2024.

Derivatives, net. During the three months ended September 30, 2025 and 2024, we recorded a gain of $3.6 million and a gain of $15.3 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.

Income tax expense. For the three months ended September 30, 2025 and 2024, changes to our effective tax rates are driven by which tax jurisdictions our income (loss) before income taxes is generated. The jurisdictions in which we operate have statutory tax rates ranging from 0% to 35%.

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Nine months ended September 30, 2025 compared to nine months ended September 30, 2024


	Nine Months Ended
	September 30,				Increase
	2025		2024		(Decrease)
	(In thousands)
Revenues and other income:
Oil and gas revenue	$	993,729	$	1,277,797	$	(284,068)
Gain on sale of assets	600		—		600
Other income, net	849		109		740
Total revenues and other income	995,178		1,277,906		(282,728)
Costs and expenses:
Oil and gas production	558,122		377,822		180,300
Exploration expenses	68,686		39,992		28,694
General and administrative	58,215		76,724		(18,509)
Depletion, depreciation and amortization	413,449		311,750		101,699

Interest and other financing costs, net	164,595		75,839		88,756
Derivatives, net	(18,480)		5,716		(24,196)
Other expenses, net	14,854		6,418		8,436
Total costs and expenses	1,259,441		894,261		365,180
Income (loss) before income taxes	(264,263)		383,645		(647,908)
Income tax expense	58,382		187,215		(128,833)
Net income (loss)	$	(322,645)	$	196,430	$	(519,075)

Oil and gas revenue. Oil and gas revenue decreased by $284.1 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of lower average realized oil and gas prices and lower production and sales volume at Jubilee and Ceiba offset by increased sales volumes in Mauritania & Senegal with first LNG cargo sales beginning in 2025. We sold 16,624 MBoe at an average realized price per barrel equivalent of $59.78 during the nine months ended September 30, 2025 and 17,465 MBoe at an average realized price per barrel equivalent of $73.16 during the nine months ended September 30, 2024.

Oil and gas production. Oil and gas production costs increased by $180.3 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal offset by lower average oil and gas operating costs at Jubilee and Ceiba.

Exploration expenses. Exploration expenses increased by $28.7 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of approximately $51.1 million of exploration expense for the nine months ended September 30, 2025 related to the Winterfell-4 step out well which was plugged and abandoned during the third quarter of 2025 offset by decreased geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.

General and administrative expenses. General and administrative expenses decreased during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of a reduction in employee compensation during 2025.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $101.7 million during the nine months ended September 30, 2025, as compared with the nine months ended September 30, 2024 primarily as a result of higher depletion rates per boe across our portfolio.

Interest and other financing costs, net. Interest and other financing costs, net increased $88.8 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024, primarily as a result of decreased capitalized interest related to the GTA Phase 1 project post first gas production in December 2024 partially offset by

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a $24.8 million loss on debt modifications and extinguishments related to the amendment and restatement of the Facility during the second quarter of 2024.

Derivatives, net. During the nine months ended September 30, 2025 and 2024, we recorded a gain of $18.5 million and a loss of $5.7 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. For the nine months ended September 30, 2025 and 2024, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rate applicable to our Ghanaian and 25% statutory tax rate applicable to our Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

Liquidity and Capital Resources

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

Oil prices are historically volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This oil price volatility 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 2025.

As such, our 2025 capital budget is based on our exploitation and production plans for Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our appraisal and development activities in the Gulf of America, Mauritania and Senegal.

Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploration, appraisal and exploitation 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 exploration, appraisal, exploitation and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.

As of September 30, 2025, borrowings under the Facility totaled approximately $1.1 billion and the undrawn availability under the Facility was $225.0 million. In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion. In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes this covenant less restrictive for the two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations.

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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, 2025 and 2024:


	Nine Months Ended
	September 30,
	2025		2024
	(In thousands)
Sources of cash, cash equivalents and restricted cash:
Net cash provided by operating activities	$	98,712	$	502,502
Net proceeds from issuance of senior notes	—		885,285
Borrowings under long-term debt	375,000		275,000

	473,712		1,662,787
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets	244,133		772,238

Notes receivable and other investing activities	86,791		2,575
Payments on long-term debt	150,000		350,000
Purchase of capped call transactions	—		49,800
Repurchase of senior notes	—		499,515

Other financing costs	1		35,534
	480,925		1,709,662
Decrease in cash, cash equivalents and restricted cash	$	(7,213)	$	(46,875)

Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2025 was $98.7 million compared with net cash provided by operating activities for the nine months ended September 30, 2024 of $502.5 million. The decrease in cash provided by operating activities in the nine months ended September 30, 2025 when compared to the same period in 2024 is primarily a result of lower average realized oil and gas prices, lower sales volumes in Ghana and Equatorial Guinea partially offset by increased sales volumes in Mauritania & Senegal with first LNG cargo sales beginning in 2025 and higher oil and gas production costs related to the ramp-up of LNG production at the GTA Phase 1 project for the nine months ended September 30, 2025.

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The following table presents our liquidity and financial position as of September 30, 2025 and December 31, 2024:


	September 30, 2025		December 31, 2024
	(In thousands)
Outstanding debt principal balances:
Facility	$	1,125,000	$	900,000
7.125% Senior Notes	250,000		250,000
7.750% Senior Notes	350,000		350,000
7.500% Senior Notes	400,274		400,274
8.750% Senior Notes	500,000		500,000
3.125% Convertible Senior Notes	400,000		400,000

Total long-term debt	3,025,274		2,800,274
Cash and cash equivalents	64,032		84,972
Total restricted cash	14,032		305
Net debt	$	2,947,210	$	2,714,997

Availability under the Facility	$	225,000	$	450,000
Availability under the GoA Term Loan Facility(1)	$	250,000	$	—
Available borrowings plus cash and cash equivalents	$	539,032	$	534,972

(1)As of September 30, 2025, the undrawn availability under the GoA Term Loan Facility was $250 million, subject to certain conditions on borrowing. On October 1, 2025, we received net proceeds of $147.2 million after deducting fees and other expenses. On October 6, 2025, the net proceeds were used, together with cash on hand, to fund the redemption of a portion of the 7.125% Senior Notes due 2026 totaling $150.0 million in aggregate, thereby decreasing the remaining availability under the GoA Term Loan Facility to $100 million. The proceeds from any additional borrowings on the GoA Term Loan Facility is expected to be used to fund the redemption or repayment of the remainder of the 7.125% Senior Notes due 2026.

Capital Expenditures and Investments

For our 2025 capital expenditure budget, we expect to incur capital costs as we:

• drill additional infill wells and execute exploitation and production activities in Ghana, Equatorial Guinea and the Gulf of America;

• complete development of the first phase of GTA; and

• advance appraisal and development efforts for the existing discoveries in the Gulf of America and internationally.

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 paying interests in our operations 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.

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2025 Capital Program

We estimate we will spend in aggregate less than $350 million of capital for the year ending December 31, 2025, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

•Approximately $250 million related to maintenance activities across our producing Ghana, Equatorial Guinea and Gulf of America assets, including infill development drilling and facilities integrity spend;

•Approximately $75 million related to the completion of the first phase of the GTA development in Mauritania and Senegal;

•Approximately $25 million related to progressing our appraisal and development programs in the Gulf of America, Mauritania and Senegal.

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, natural gas and LNG and the prices we receive from the sale of oil, natural gas and LNG, and our ability to effectively hedge future production volumes, the success of our multi-faceted infrastructure-led exploration, appraisal and development 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 exploration, appraisal, exploitation 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. 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. As of September 30, 2025, borrowings under the Facility totaled approximately $1.1 billion and the undrawn availability under the Facility was $225.0 million.

In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on April 1, 2027, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of December 31, 2029. As of September 30, 2025, 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. In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes this covenant less restrictive for the two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations. We were in compliance with the financial covenants contained in the Facility as of September 30, 2025 (the most recent assessment date). The Facility contains customary cross default provisions.

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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 are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility. 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 four series of senior notes outstanding as of September 30, 2025, which we collectively refer to as the “Senior Notes.” Our 7.125% Senior Notes had an outstanding balance of $250.0 million as of September 30, 2025, and mature on April 4, 2026. In October 2025, we used net proceeds from the GoA Term Loan Facility, together with cash on hand, to fund the repurchase of $150.0 million of the 7.125% Senior Notes resulting in $100.0 million remaining outstanding. Interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.750% Senior Notes have an outstanding balance of $350.0 million and mature on May 1, 2027. Interest is payable on the 7.750% Senior Notes each May 1 and November 1. Our 7.500% Senior Notes have an outstanding balance of approximately $400.3 million and mature on March 1, 2028. Interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 8.750% Senior Notes have an outstanding balance of $500.0 million and mature on October 1, 2031. Interest is payable on the 8.750% Senior Notes each April 1 and October 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 the 3.125% Convertible 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 Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company’s Gulf of America assets, and on a subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.

3.125% Convertible Senior Notes due 2030

We have one series of senior convertible notes outstanding. Our 3.125% Convertible Senior Notes mature on March 15, 2030, unless earlier converted, redeemed or repurchased. Interest is payable in arrears each March 15 and September 15, commencing September 15, 2024.

The 3.125% Convertible 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 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, to the extent of the value of the assets securing such indebtedness). The 3.125% Convertible Senior Notes are guaranteed on a senior, unsecured basis by certain of our existing subsidiaries that guarantee on a senior basis the Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries. The 3.125% Convertible Senior Notes are guaranteed on a subordinated, unsecured basis by certain of our existing subsidiaries that borrow under or guarantee the Facility and guarantee on a subordinated basis the Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries.

The 3.125% Convertible Senior Notes indenture contains customary terms and covenants.

In connection with the issuance of the 3.125% Convertible Senior Notes, the Company entered into capped call transactions (the “Capped Call Transactions”). The Capped Call Transactions are generally expected to reduce potential dilution to holders of our common stock upon any conversion of the 3.125% Convertible Senior Notes and/or offset any cash payments that we are required to make in excess of the principal amount of any 3.125% Convertible Senior Notes that are converted, as the case may be, with such reduction and/or offset subject to a cap.

GoA Term Loan Facility

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aggregate. The proceeds from any additional borrowings on the GoA Term Loan Facility is expected be used to fund the redemption or repayment of the company’s Senior Notes.

•the GoA field life coverage ratio (as defined in the glossary), not less than 1.50x; and

•the GoA net leverage ratio (as defined in the glossary), not more than 3.50x.

Contractual Obligations

The following table summarizes by period the payments due for our estimated contractual obligations as of September 30, 2025, and the weighted average interest rates expected to be paid on the Facility 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,
	2025(2)			2026			2027			2028			2029			Thereafter			Total		2025
	(In thousands, except percentages)
Fixed rate debt:
7.125% Senior Notes	$	—		$	250,000		$	—		$	—		$	—		$	—		$	250,000	$	249,448
7.750% Senior Notes	—			—			350,000			—			—			—			350,000		341,022
7.500% Senior Notes	—			—			—			400,274			—			—			400,274		352,978
8.750% Senior Notes	—			—			—			—			—			500,000			500,000		386,875
3.125% Convertible Senior Notes	—			—			—			—			—			400,000			400,000		254,000


Variable rate debt:
Weighted average interest rate	8.24		%	8.40		%	8.31		%	8.93		%	9.28		%	—		%
Facility(1)	$	—		$	—		$	219,086		$	396,487		$	509,427		$	—		$	1,125,000	$	1,125,000


Total principal debt repayments	$	—		$	250,000		$	569,086		$	796,761		$	509,427		$	900,000		$	3,025,274
Interest & commitment fee payments on long-term debt	99,999			221,189			192,088			136,775			86,710			93,750			830,511
Operating leases(3)	1,060			3,572			3,245			3,018			2,808			—			13,703
Purchase obligations(4)	18,657			—			—			—			—			—			18,657
Decommissioning Trust Funds(5)	—			11,460			11,460			11,460			11,460			80,218			126,058
Firm transportation commitments	955			4,182			2,074			—			—			—			7,211

__________________________________

(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, 2025. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

(2)Represents the period October 1, 2025 through December 31, 2025.

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

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(4)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 13 - Additional Financial Information for additional information regarding these liabilities.

(5)In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total commitment to be approximately $126.1 million as of September 30, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated 11 year period. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.

As of September 30, 2025, we have a commitment to drill one development well in Equatorial Guinea.

Once the Tortue Phase 1 SPA Commercial Operations Date is achieved, we have a commitment to our buyer under the Tortue Phase 1 SPA, BP Gas Marketing Limited, to deliver our proportionate share of a minimum annual contract quantity of LNG of 127,951,000 MMBtu, which is equivalent to approximately 2.45 million tonnes per annum, subject to certain downward adjustments by the sellers. Under certain circumstances, in the event the annual quantities provided are lower than the minimum annual contract quantity, Kosmos may be obligated to credit or pay a portion of the Contract Price to BP Gas Marketing Limited for the shortfall volumes.

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 gas reserves, asset retirement obligations 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, 2024.

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 the continued war in Ukraine and ongoing instability in the Middle East 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 LNG 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;

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•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 LNG 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;

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

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

•our vulnerability to severe weather events, including, 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 7 — Derivative Financial Instruments and Note 8— 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.

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The following table reconciles the changes that occurred in fair values of our open derivative contracts during the nine months ended September 30, 2025:


	Derivative Contracts Assets (Liabilities)
	Commodities		Interest Rates		Total
	(In thousands)
Fair value of contracts outstanding as of December 31, 2024	$	9,468	$	2,202	$	11,670
Changes in contract fair value	9,909		766		10,675
Contract maturities	(11)		(2,790)		(2,801)
Fair value of contracts outstanding as of September 30, 2025	$	19,366	$	178	$	19,544

Commodity Price Risk

The Company’s revenues, earnings, cash flows, capital investments, debt capacity 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 2025 ranged between $61.09 and $83.06 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first nine months of 2025.

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 swaps, 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.

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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, 2025. 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)		Swap		Put		Floor		Ceiling		2025(2)
														(In thousands)
2025:
Oct - Dec	Two-way collars	Dated Brent	2,000	$	1.35	$	—	$	—	$	60.00	$	74.94	$	(1,092)
Oct - Dec	Three-way collars	Dated Brent	500	1.13		—		55.00		70.00		85.00		1,553
2026:
Jan - Jun	Two-way collars	Dated Brent	1,000	1.55		—		—		60.00		74.75		(393)
Jan - Dec	Three-way collars	Dated Brent	2,000	—		—		50.00		60.00		75.51		(10)
Jan - Jun	Swaps(1)	Dated Brent	1,000	—		72.90		—		—		80.00		6,412
Jan - Dec	Swaps(1)	Dated Brent	1,000	—		72.46		—		—		80.00		5,528
Jan - Dec	Swaps(1)	Dated Brent	2,000	—		69.70		55.00		—		—		4,234
Jan - Dec	Swaps(1)	NYMEX WTI	1,500	—		64.83		50.00		—		—		2,134

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(1)Includes option contracts sold to counterparties to enhance Swaps.

(2)Fair values are based on the average forward oil prices on September 30, 2025.

At September 30, 2025, our open commodity derivative instruments were in a net asset position of $18.4 million. As of September 30, 2025, a hypothetical 10% price increase in the oil price curves would decrease future pre-tax earnings by approximately $53.6 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $47.3 million. For example, if oil prices averaged $50.00 or $60.00 per barrel the rest of 2025 and 2026, our average realized pricing after derivatives would be approximately $56.00 and $62.00 per barrel, respectively, excluding any impact of differentials.

Interest Rate Derivative Instruments

See Note 7 — Derivative Financial Instruments and Note 8 — Fair Value Measurements for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.

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, 2025 total approximately $1.1 billion and have a weighted average interest rate of 8.2%, 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%, our weighted average interest rate would increase to approximately 8.5%. At this level of floating rate debt, we would pay an estimated additional $4.4 million interest expense per year. The impact of the 2025 fixed interest rate swap would reduce the estimated additional interest expense to $0.6 million for the three months ending December 31, 2025. The commitment fees on the undrawn availability under the Facility 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 and future payments associated with the GTA FPSO arrangement.

As of September 30, 2025, the fair market value of our interest rate swaps was a net asset of approximately $0.2 million. If SOFR changed by 10%, it would have a negligible impact on the fair market value of our interest rate swaps.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2025, 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, 2024.

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.

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Item 5. Other Information.

Rule 10b5-1 and Non Rule 10b5-1 Trading Arrangements

During the nine months ended September 30, 2025, certain of our officers and directors adopted or terminated Rule 10b5-1 trading arrangements as follows.

On February 27, 2025, Sir John Grant, a member of our board of directors, adopted a trading plan intended to satisfy the conditions under Rule 10b5-1(c) of the Exchange Act. Sir John Grant’s plan was for the sale of up to 27,923 shares of our common stock on June 5, 2025, in order to cover income tax liability from the vesting of restricted share units that were granted to him under the Company’s Long Term Incentive Plan. Sir John Grant sold 27,923 shares on June 5, 2025 and the plan has now been terminated.

During the nine months ended September 30, 2025, none of our officers or directors adopted or terminated any non-Rule 10b5-1 trading arrangement.

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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 3, 2025	/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						Transition Agreement between Kosmos Energy, LLC and Chris topher J. Ba l l dated August 21, 2025.

10.2						Advisory Agreement between Kosmos Energy, LLC and Christopher J. Ball dated August 21, 2025.

10.3						S enior Secured Term Loan Credit Agreement, dated September 24, 2025, among Kosmos Energy Gulf of Mexico Operations, LLC , as Borrower, the other Loan Parties party thereto from time to time , Shell Trading (US) Company , as Lender , and Ankura Trust Company , LLC , as the Collateral Agent and Administrative Agent.

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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