UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| (Mark One) | |||||
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the quarterly period ended June 30, 2026
☐ | 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 July 30, 2026 | |||||||
| Common Shares, $0.01 par value | 595,487,651 | |||||||
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 | |||||
| PART II. OTHER INFORMATION | |||||
2
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. | |||||||
| “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 in the Facility, for each applicable calculation date, as the ratio of (x) total long‑term debt and finance lease liabilities 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. | |||||||
| “Facility” | Facility agreement dated March 28, 2011 (as amended or as amended and restated from time to time). | |||||||
3
| “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 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 Nordic bonds” | 11.250% senior secured bonds due in 2031 in the Nordic Market | |||||||
| “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 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. | |||||||
“Mcfe” | Thousand cubic feet of natural gas equivalent. | |||||||
4
| “Mcfpd” | Thousand cubic feet per day of natural gas. | |||||||
| “MMBbl” | Million barrels of oil. | |||||||
| “MMBoe” | Million barrels of oil equivalent. | |||||||
| “MMBtu” | Million British thermal units. | |||||||
| “MMcf” | Million cubic feet of natural gas. | |||||||
| “MMcfd” | Million cubic feet per day of natural gas. | |||||||
| “MMTPA” | Million metric tonnes per annum. | |||||||
| “Natural gas liquid” or “NGL” | Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others. | |||||||
| “Net debt” | Total long-term debt less cash and cash equivalents and total restricted cash. | |||||||
| “NYSE” | New York Stock Exchange. | |||||||
| “Petroleum contract” | A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area. | |||||||
| “Petroleum system” | A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate. | |||||||
| “Plan of development” or “PoD” | A written document outlining the steps to be undertaken to develop a field. | |||||||
| “Productive well” | An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. | |||||||
| “Prospect(s)” | A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes. | |||||||
| “Proved reserves” | Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S‑X 4‑10(a)(2). | |||||||
| “Proved developed reserves” | Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. | |||||||
| “Proved undeveloped reserves” | Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects. | |||||||
| “RSC” | Ryder Scott Company, L.P. | |||||||
| “SOFR” | Secured Overnight Financing Rate | |||||||
| “SEC” | Securities and Exchange Commission. | |||||||
| “7.125% Senior Notes” | 7.125% Senior Notes due 2026. | |||||||
| “7.750% Senior Notes” | 7.750% Senior Notes due 2027. | |||||||
| “7.500% Senior Notes” | 7.500% Senior Notes due 2028. | |||||||
“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. | |||||||
| “TEN” | Tweneboa, Enyenra and Ntomme. | |||||||
5
“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. | |||||||
“Tullow” | Tullow Oil plc. | |||||||
| “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. | |||||||
6
KOSMOS ENERGY LTD.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
| June 30, 2026 | December 31, 2025 | ||||||||||
| (Unaudited) | |||||||||||
| Assets | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 102,137 | $ | 91,518 | |||||||
| Restricted cash | 23,505 | — | |||||||||
| Receivables | 113,022 | 103,472 | |||||||||
| Inventories | 139,947 | 172,640 | |||||||||
| Prepaid expenses and other | 13,673 | 12,428 | |||||||||
| Derivatives | 459 | 47,816 | |||||||||
| Total current assets | 392,743 | 427,874 | |||||||||
| Property and equipment, net | 3,351,526 | 3,733,784 | |||||||||
| Other assets: | |||||||||||
| Restricted cash | 30,589 | 26,226 | |||||||||
| Long-term receivables | 472,897 | 458,793 | |||||||||
| Deferred tax assets | 2,757 | 3,946 | |||||||||
| Derivatives | 2,335 | 2,681 | |||||||||
| Other | 57,300 | 43,322 | |||||||||
| Total assets | $ | 4,310,147 | $ | 4,696,626 | |||||||
| Liabilities and stockholders’ equity | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 161,981 | $ | 202,555 | |||||||
| Accrued liabilities | 343,879 | 237,609 | |||||||||
| Current maturities of long-term debt | 145,303 | 132,143 | |||||||||
| Derivatives | 11,633 | — | |||||||||
| Total current liabilities | 662,796 | 572,307 | |||||||||
| Long-term liabilities: | |||||||||||
| Long-term debt, net | 2,526,872 | 2,920,616 | |||||||||
| Derivatives | 5,129 | — | |||||||||
| Asset retirement obligations | 203,444 | 327,016 | |||||||||
| Deferred tax liabilities | 177,375 | 305,924 | |||||||||
| Other long-term liabilities | 29,634 | 42,173 | |||||||||
| Total long-term liabilities | 2,942,454 | 3,595,729 | |||||||||
| Stockholders’ equity: | |||||||||||
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2026 and December 31, 2025 | — | — | |||||||||
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 638,126,969 and 522,590,223 issued at June 30, 2026 and December 31, 2025, respectively | 6,381 | 5,226 | |||||||||
| Additional paid-in capital | 2,758,578 | 2,542,627 | |||||||||
| Accumulated deficit | (1,823,055) | (1,782,256) | |||||||||
Treasury stock, at cost, 44,263,269 shares at June 30, 2026 and December 31, 2025, respectively | (237,007) | (237,007) | |||||||||
| Total stockholders’ equity | 704,897 | 528,590 | |||||||||
| Total liabilities and stockholders’ equity | $ | 4,310,147 | $ | 4,696,626 | |||||||
See accompanying notes.
7
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
| Three Months Ended | Six Months Ended | ||||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Oil and gas revenue | $ | 607,253 | $ | 392,635 | $ | 977,981 | $ | 682,770 | |||||||||||||||
| Gain on sale of assets | 9,421 | 600 | 9,421 | 600 | |||||||||||||||||||
| Other income, net | 361 | 283 | 530 | 579 | |||||||||||||||||||
| Total revenues and other income | 617,035 | 393,518 | 987,932 | 683,949 | |||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Oil and gas production | 179,429 | 243,118 | 310,024 | 410,426 | |||||||||||||||||||
| Exploration expenses | 3,197 | 4,069 | 22,941 | 13,738 | |||||||||||||||||||
| General and administrative | 19,263 | 19,074 | 46,973 | 45,329 | |||||||||||||||||||
| Depletion, depreciation and amortization | 120,501 | 151,268 | 240,374 | 271,935 | |||||||||||||||||||
| Interest and other financing costs, net | 53,700 | 54,834 | 112,502 | 106,676 | |||||||||||||||||||
| Derivatives, net | (51,809) | (21,566) | 200,187 | (14,834) | |||||||||||||||||||
| Other expenses, net | 10,281 | 6,481 | 13,545 | 8,470 | |||||||||||||||||||
| Total costs and expenses | 334,562 | 457,278 | 946,546 | 841,740 | |||||||||||||||||||
| Income (loss) before income taxes | 282,473 | (63,760) | 41,386 | (157,791) | |||||||||||||||||||
| Income tax expense | 97,698 | 23,980 | 82,185 | 40,555 | |||||||||||||||||||
| Net income (loss) | $ | 184,775 | $ | (87,740) | $ | (40,799) | $ | (198,346) | |||||||||||||||
| Net income (loss) per share: | |||||||||||||||||||||||
| Basic | $ | 0.31 | $ | (0.18) | $ | (0.07) | $ | (0.42) | |||||||||||||||
| Diluted | $ | 0.31 | $ | (0.18) | $ | (0.07) | $ | (0.42) | |||||||||||||||
Weighted average number of shares used to compute net income (loss) per share: | |||||||||||||||||||||||
| Basic | 593,441 | 478,068 | 550,060 | 476,881 | |||||||||||||||||||
| Diluted | 604,713 | 478,068 | 550,060 | 476,881 | |||||||||||||||||||
See accompanying notes.
8
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
(Unaudited)
| Additional | |||||||||||||||||||||||||||||||||||
| Common Shares | Paid-in | Accumulated | Treasury | ||||||||||||||||||||||||||||||||
| Shares | Amount | Capital | Deficit | Stock | Total | ||||||||||||||||||||||||||||||
2026: | |||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2025 | 522,590 | $ | 5,226 | $ | 2,542,627 | $ | (1,782,256) | $ | (237,007) | $ | 528,590 | ||||||||||||||||||||||||
| Equity-based compensation | — | — | 5,950 | — | — | 5,950 | |||||||||||||||||||||||||||||
| Restricted stock units | 2,698 | 27 | (27) | — | — | — | |||||||||||||||||||||||||||||
Public offering of common stock | 112,125 | 1,121 | 205,022 | — | — | 206,143 | |||||||||||||||||||||||||||||
| Net loss | — | — | — | (225,574) | — | (225,574) | |||||||||||||||||||||||||||||
| Balance as of March 31, 2026 | 637,413 | 6,374 | 2,753,572 | (2,007,830) | (237,007) | 515,109 | |||||||||||||||||||||||||||||
| Equity-based compensation | — | — | 5,018 | — | — | 5,018 | |||||||||||||||||||||||||||||
| Restricted stock units | 714 | 7 | (7) | — | — | — | |||||||||||||||||||||||||||||
Tax withholdings and cash settlements on restricted stock units | — | — | (5) | — | — | (5) | |||||||||||||||||||||||||||||
| Net income | — | — | — | 184,775 | — | 184,775 | |||||||||||||||||||||||||||||
| Balance as of June 30, 2026 | 638,127 | 6,381 | 2,758,578 | (1,823,055) | (237,007) | 704,897 | |||||||||||||||||||||||||||||
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 awards and 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 | |||||||||||||||||||||||||||||
See accompanying notes.
9
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
| Six Months Ended June 30, | |||||||||||
| 2026 | 2025 | ||||||||||
| Operating activities | |||||||||||
| Net loss | $ | (40,799) | $ | (198,346) | |||||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||
| Depletion, depreciation and amortization (including deferred financing costs) | 245,671 | 275,708 | |||||||||
| Deferred income taxes | (1,268) | 1,636 | |||||||||
| Unsuccessful well costs and leasehold impairments | 13,959 | 162 | |||||||||
| Change in fair value of derivatives | 262,292 | (7,883) | |||||||||
Cash settlements on derivatives, net (including $(135.7) million and $9.7 million on commodity hedges during 2026 and 2025) | (198,684) | 6,281 | |||||||||
| Equity-based compensation | 14,064 | 15,707 | |||||||||
| Gain on sale of assets | (9,421) | (600) | |||||||||
| Debt modifications and extinguishments | (1,081) | — | |||||||||
| Other | (20,759) | (8,506) | |||||||||
| Changes in assets and liabilities: | |||||||||||
| (Increase) decrease in receivables | (19,990) | 70,659 | |||||||||
| Decrease in inventories and prepaid expenses | 17,209 | 7,542 | |||||||||
| Increase (decrease) in accounts payable and accrued liabilities | 20,373 | (36,080) | |||||||||
| Net cash provided by operating activities | 281,566 | 126,280 | |||||||||
| Investing activities | |||||||||||
| Oil and gas assets | (163,477) | (172,766) | |||||||||
| Proceeds on sale of assets | 127,034 | — | |||||||||
Notes receivable and other investing activities | (11,598) | (86,791) | |||||||||
| Net cash used in investing activities | (48,041) | (259,557) | |||||||||
| Financing activities | |||||||||||
| Borrowings under long-term debt | 124,167 | 200,000 | |||||||||
| Payments on long-term debt | (504,738) | (100,000) | |||||||||
| Net proceeds from issuance of senior notes and bonds | 350,000 | — | |||||||||
| Repurchase and redemption of senior notes | (347,184) | — | |||||||||
| Net proceeds from issuance of common stock | 206,440 | — | |||||||||
| Payments on finance lease | (14,951) | — | |||||||||
Other financing costs | (8,772) | (1) | |||||||||
| Net cash provided by (used in) financing activities | (195,038) | 99,999 | |||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | 38,487 | (33,278) | |||||||||
| Cash, cash equivalents and restricted cash at beginning of period | 117,744 | 85,277 | |||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 156,231 | $ | 51,999 | |||||||
| Supplemental cash flow information | |||||||||||
| Cash paid for: | |||||||||||
| Interest, net of capitalized interest | $ | 108,469 | $ | 101,377 | |||||||
| Income taxes, net of refund received | $ | 47,908 | $ | 69,296 | |||||||
See accompanying notes.
10
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, 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 three geographic areas: Ghana, Mauritania/Senegal and the Gulf of America.
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, 2025, included in our annual report on Form 10-K.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no significant impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities, stockholders’ equity or cash flows.
Cash, Cash Equivalents and Restricted Cash
| June 30, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
| Cash and cash equivalents | $ | 102,137 | $ | 91,518 | |||||||
| Restricted cash - current | 23,505 | — | |||||||||
| Restricted cash - long-term | 30,589 | 26,226 | |||||||||
| Total cash, cash equivalents and restricted cash in the consolidated statements of cash flows | $ | 156,231 | $ | 117,744 | |||||||
Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. When our 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 7.750% 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. During the first quarter of 2025, the Facility lenders waived the requirement to
11
maintain a restricted cash balance until the March 31, 2026 financial covenant test date. During the second quarter of 2026, the Facility lenders agreed to reduce the amount of the required restricted cash balance to three months of interest and fees until the September 30, 2026 financial covenant test date, after which the amount of the required restricted cash balance will be determined as usual. Our debt cover ratio for the most recent March 31, 2026 financial covenant test date exceeded 2.50x and the estimated restricted cash funding requirement is approximately $23.5 million. As of June 30, 2026, we have funded approximately $23.5 million into the debt service reserve account as required under the terms of the Facility. Restricted cash – long-term primarily represents cash and cash equivalents collateralized, in accounts held by us, as required to support existing performance obligations in the Gulf of America.
Inventories
Inventories consisted of $132.4 million and $144.9 million of materials and supplies and $7.5 million and $27.7 million of hydrocarbons as of June 30, 2026 and December 31, 2025, 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.
Assets and Liabilities Held for Sale
The Company classifies disposal groups as held for sale in the period in which all of the following criteria are met: (1) management, having the authority to approve the action, commits to a plan to sell the disposal group; (2) the disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such disposal groups; (3) an active program to locate a buyer or buyers and other actions required to complete the plan to sell the disposal group have been initiated; (4) the sale of the disposal group is probable, and the transfer of the disposal group is expected to qualify for recognition as a completed sale, within one year, except if events or circumstances beyond the Company’s control extended the period of time required to sell the disposal group beyond one year; (5) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value; and (6) actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn.
A disposal group that is classified as held for sale is initially measured at the lower of its carrying amount or fair value less any costs to sell. Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Subsequent changes in fair value of a disposal group less any costs to sell are reported as an adjustment to the carrying amount of the disposal group, as long as the new carrying amount does not exceed the carrying amount of the assets at the time it was initially classified as held for sale. Depreciation, depletion and amortization expense is not recorded on assets to be divested once they are classified as held for sale. In the initial period in which the disposal group meets the criteria to be classified as held for sale, the assets and liabilities of the disposal group are separately presented as assets held for sale and liabilities held for sale, respectively, in the Consolidated Balance Sheets.
Revenue Recognition
Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a derivative that is separated from the host contract for accounting purposes. The host contract is the receivable from 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.
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Oil and gas revenue is composed of the following:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
Revenues from contracts with customers: | |||||||||||||||||||||||
Ghana | $ | 365,880 | $ | 212,880 | $ | 616,032 | $ | 365,685 | |||||||||||||||
Equatorial Guinea | 47,464 | 63,196 | 71,951 | 96,878 | |||||||||||||||||||
| Mauritania|Senegal | 93,596 | 20,239 | 145,862 | 22,936 | |||||||||||||||||||
Gulf of America | 111,439 | 103,100 | 206,241 | 204,878 | |||||||||||||||||||
Total revenues from contracts with customers | 618,379 | 399,415 | 1,040,086 | 690,377 | |||||||||||||||||||
| Provisional sales contracts | (11,126) | (6,780) | (62,105) | (7,607) | |||||||||||||||||||
| Oil and gas revenue | $ | 607,253 | $ | 392,635 | $ | 977,981 | $ | 682,770 | |||||||||||||||
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 of the purchasers identified by our marketing agents would not have a long‑term material adverse effect on our financial position or results of Ghana operations. Customers in our Gulf of America and Mauritania | Senegal business units that comprise 10% or more of our total consolidated oil and gas revenue for the three and six months ended June 30, 2026 and 2025, are shown below.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
(Percentage) | |||||||||||||||||||||||
Customer | |||||||||||||||||||||||
BP plc | 77 | % | 18 | % | 62 | % | 19 | % | |||||||||||||||
Shell Trading (US) Company | 18 | % | 4 | % | 20 | % | 5 | % | |||||||||||||||
Recent Accounting Standards
Not Yet Adopted
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. Acquisitions and Divestitures
On February 24, 2026, the Company entered into a Share Sale and Purchase Agreement with a subsidiary of Panoro Energy ASA for the sale of all of our 40.4% participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. The transaction closed on June 16, 2026.
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Pursuant to the terms of the purchase agreement, Kosmos received final cash consideration of approximately $127.0 million, based on the initial purchase price of $180.0 million reduced by certain purchase price adjustments totaling approximately $53.0 million. The Company is also entitled to future contingent consideration of up to $39.5 million, comprised of $12.5 million linked to future production performance at the Ceiba field, and $9.0 million payable in each of the years 2027, 2028 and 2029, subject to certain production and oil price thresholds.
The proceeds from the transaction were used to repay borrowings under the Facility in June 2026.
Management considers the assets and liabilities in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea included in the Share Sale and Purchase Agreement as a disposal group. The disposal group had previously been classified as held for sale. The following table summarizes the carrying amounts of the major classes of assets and liabilities included in the disposal group as of the date of sale:
| As of date of sale | |||||
(In thousands) | |||||
| Assets | |||||
Current assets: | |||||
Cash and cash equivalents | $ | — | |||
Receivables | — | ||||
Inventories | 9,100 | ||||
Prepaid expenses and other | 737 | ||||
Total current assets | 9,837 | ||||
Non-current assets: | |||||
Property and equipment, net | 410,458 | ||||
Total non-current assets | 410,458 | ||||
| Total assets of disposal group | $ | 420,295 | |||
| Liabilities | |||||
Current liabilities: | |||||
Accounts Payable | $ | 34,376 | |||
Accrued Liabilities | — | ||||
Total current liabilities | 34,376 | ||||
Long-term Liabilities | |||||
Asset retirement obligations | 142,211 | ||||
Deferred tax liabilities | 126,092 | ||||
Total long-term liabilities | 268,303 | ||||
| Total liabilities of disposal group | $ | 302,679 | |||
Upon closing, the Company recognized a gain on sale of assets of approximately $9.4 million, representing the excess of net proceeds received over the carrying value of the disposal group. The Company evaluated the future contingent consideration and determined that no amounts were recognized at closing as realization is contingent upon future production and commodity price conditions. Any contingent consideration will be recognized when realized. The divestiture does not meet the criteria to be reported as discontinued operations as it does not represent a strategic shift for the Company. Accordingly, the operating results for the disposal group are included in continuing operations in the Company’s Consolidated Statement of Operations through the date of sale in June 2026.
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4. Receivables
Receivables consisted of the following:
| June 30, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
Joint interest billings, net | $ | 13,780 | $ | 17,255 | |||||||
Oil and gas sales | 90,369 | 56,700 | |||||||||
Other current receivables | 8,873 | 29,517 | |||||||||
Total receivables | $ | 113,022 | $ | 103,472 | |||||||
Long-term receivables | $ | 472,897 | $ | 458,793 | |||||||
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.
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. As of June 30, 2026 and December 31, 2025, the balance due from the national oil companies including accrued interest was $450.9 million and $437.1 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. Interest income on the long-term notes receivable was $7.0 million and $6.2 million for the three months ended June 30, 2026 and 2025, respectively, and $13.8 million and $11.5 million for the six months ended June 30, 2026 and 2025.
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5. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
| June 30, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
| Oil and gas properties: | |||||||||||
| Proved properties | $ | 7,763,259 | $ | 8,301,679 | |||||||
| Unproved properties | 210,786 | 210,161 | |||||||||
| Total oil and gas properties | 7,974,045 | 8,511,840 | |||||||||
| Accumulated depletion | (4,624,781) | (4,780,826) | |||||||||
Oil and gas properties, net | 3,349,264 | 3,731,014 | |||||||||
| Other property | 69,046 | 68,255 | |||||||||
| Accumulated depreciation | (66,784) | (65,485) | |||||||||
| Other property, net | 2,262 | 2,770 | |||||||||
| Property and equipment, net | $ | 3,351,526 | $ | 3,733,784 | |||||||
We recorded depletion expense of $111.8 million and $141.7 million for the three months ended June 30, 2026 and 2025, respectively, and $223.5 million and $253.1 million for the six months ended June 30, 2026 and 2025, respectively. During the six months ended June 30, 2026, the decrease in oil and gas properties, net is primarily due to the sale of the Ceiba and Okume Complex production assets located in Block G offshore Equatorial Guinea in June 2026. See Note 3 - Acquisitions and Divestitures. Additions to our proved properties during the six months ended June 30, 2026 primarily related to infill development costs in the Jubilee Field in Ghana and at Winterfell-5 in the Gulf of America. Additionally, in February 2026, Tullow Oil plc, as Operator of the TEN partnership, executed the final Sale and Purchase Agreement enabling the partnership to acquire the TEN FPSO from MODEC, Inc. at the end of its current lease in 2027 for a gross purchase price of $205.0 million. As a result, proved property additions for the period ended June 30, 2026 include $88.2 million for our proportionate share of the finance lease asset, with a corresponding finance lease liability in accrued liabilities. These non-cash impacts are excluded from the statement of cash flows.
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6. Suspended Well Costs
The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the six months ended June 30, 2026.
| June 30, 2026 | |||||
| (In thousands) | |||||
| Beginning balance | $ | 73,141 | |||
| Additions to capitalized exploratory well costs pending the determination of proved reserves | 4,985 | ||||
| Reclassification due to determination of proved reserves | — | ||||
| Capitalized exploratory well costs charged to expense | — | ||||
| Ending balance | $ | 78,126 | |||
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:
| June 30, 2026 | December 31, 2025 | ||||||||||
| (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 | 78,126 | 73,141 | |||||||||
Exploratory well costs capitalized for a period of six to ten years | — | — | |||||||||
| Ending balance | $ | 78,126 | $ | 73,141 | |||||||
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | 1 | 1 | |||||||||
As of June 30, 2026, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Tiberius discovery in Keathley Canyon Block 964 in the Outer Wilcox play in the Gulf of America.
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 July 2026, we completed a farm-out of Tiberius, reducing our interest to 33.34%. The Tiberius project is being progressed as a phased development. A production handling agreement for the Oxy operated Lucius platform was signed in the third quarter of 2025, contracts for the fabrication and installation of the Tiberius subsea production system have been executed and a final investment decision for the development was achieved by the partnership in March 2026.
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7. Leases
We have commitments under operating leases primarily related to office leases and as well as the commitment under the TEN FPSO finance lease. Our leases have initial lease terms ranging from one year to ten years. Certain lease agreements contain provisions for future rent increases.
Other information related to operating and finance leases at June 30, 2026 and December 31, 2025, is as follows:
| June 30, 2026 | December 31, 2025 | ||||||||||
(In thousands, except lease term discount rate) | |||||||||||
Balance sheet classifications | |||||||||||
Operating leases | |||||||||||
| Other assets (right-of-use assets) | $ | 8,705 | $ | 10,059 | |||||||
Accrued liabilities (current maturities of leases) | 3,060 | 2,777 | |||||||||
| Other long-term liabilities (non-current maturities of leases) | 7,852 | 9,438 | |||||||||
Finance leases | |||||||||||
| Property and equipment, net(1) | 69,454 | — | |||||||||
Accrued liabilities | 73,203 | — | |||||||||
(1) Represents $88.2 million of proved property additions or our proportionate share of the TEN FPSO finance lease asset offset by depletion expense of approximately $18.7 million for the period ended June 30, 2026.
Future minimum rental commitments under our leases as of June 30, 2026, are as follows:
Operating Leases(1) | Financing Leases(1) | ||||||||||
(In thousands) | |||||||||||
2026(2) | $ | 2,017 | $ | 24,504 | |||||||
| 2027 | 3,951 | 52,514 | |||||||||
| 2028 | 3,744 | — | |||||||||
| 2029 | 3,176 | — | |||||||||
| 2030 | — | — | |||||||||
Thereafter | — | — | |||||||||
Total undiscounted lease payments | $ | 12,888 | $ | 77,018 | |||||||
Less: Imputed interest | (1,976) | (3,815) | |||||||||
Total lease liabilities | $ | 10,912 | $ | 73,203 | |||||||
__________________________________
(1) Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.
(2) Represents the period July 1, 2026 through December 31, 2026
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8. Debt
| June 30, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
| Outstanding debt principal balances: | |||||||||||
| Facility | $ | 773,000 | $ | 1,200,000 | |||||||
7.125% Senior Notes | — | 100,000 | |||||||||
7.750% Senior Notes | 99,973 | 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 | |||||||||
11.250% Senior Secured Bonds | 350,000 | — | |||||||||
| GoA Term Loan Facility | 196,429 | 150,000 | |||||||||
| Total long-term debt | 2,719,676 | 3,100,274 | |||||||||
| Unamortized deferred financing costs and discounts(1) | (47,501) | (47,515) | |||||||||
| Total debt, net | 2,672,175 | 3,052,759 | |||||||||
| Less: Current maturities of long-term debt | (145,303) | (132,143) | |||||||||
| Long-term debt, net | $ | 2,526,872 | $ | 2,920,616 | |||||||
(1)Includes $21.7 million and $24.3 million of unamortized deferred financing costs related to the Facility, $8.0 million and $10.4 million of unamortized deferred financing costs and discounts related to the Senior Notes, and $8.0 million and $9.0 million of unamortized deferred financing costs related to the 3.125% Convertible Senior Notes, $6.3 million and $0.8 million of unamortized deferred financing costs related to the 11.250% Senior Secured Bonds and $3.5 million and $3.0 million of unamortized deferred financing costs related to the GoA Term Loan Facility as of June 30, 2026 and December 31, 2025, respectively.
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. In April 2026, during the Spring 2026 redetermination, the Company’s lending syndicate approved a borrowing base at approximately $1.25 billion. The borrowing base amount was 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. Following the closing of the sale of all our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea on June 16, 2026, the Company’s production assets in Equatorial Guinea are no longer included in the borrowing base amount, and, as agreed with the lending syndicate, the borrowing base has been reduced to approximately $1.2 billion. As of June 30, 2026, borrowings under the Facility totaled approximately $0.8 billion and the undrawn availability under the Facility was approximately $440 million. Final maturity of the Facility is December 31, 2029.
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 June 30, 2026, 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 7.750% 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. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance until the financial covenant test date to be calculated on March 31, 2026. During the second quarter of 2026, the Facility lenders agreed to reduce the amount of the required restricted cash balance to three months of interest and fees until the September 30, 2026 financial
19
covenant test date, after which the amount of the required restricted cash balance will be determined as usual. Our debt cover ratio for the most recent March 31, 2026 financial covenant test date exceeded 2.50x and the estimated restricted cash funding requirement is approximately $23.5 million. As of June 30, 2026 we have funded approximately $23.5 million into the debt service reserve account as required under the terms of the Facility.
In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment made this covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returned to the originally agreed upon ratio of 3.50x for assessment dates thereafter. In February 2026, we further amended the debt cover ratio calculation through September 2026. This most recent amendment makes the covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.5x and 4.25x respectively, and for purposes of the financial covenant assessment date in March 2026, the calculation was made excluding the Company’s Mauritania and Senegal business unit. The debt cover ratio returns to the originally agreed upon ratio of 3.5x for assessment dates thereafter.
We were in compliance with the financial covenants, as amended, contained in the Facility as of the most recent assessment date. 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.
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”). 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. In January 2026, we used the proceeds from funding the second tranche under the GoA Term Loan Facility, together with cash on hand, to complete the redemption of the remaining outstanding balance amount of $100.0 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 7.500% 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 7.500% 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. In the first half of 2026, the Company used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $250.0 million of the 7.750% Senior Notes pursuant to the Company’s cash tender offer announced on January 12, 2026 and open market repurchases. 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 7.750% 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 7.750% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes.
20
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.
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 7.750% 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 7.750% 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 7.750% 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 7.750% 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 7.750% 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 and cross default provisions.
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 June 30, 2026, 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 June 30, 2026, 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.
21
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 with net proceeds received of $147.2 million after deducting fees and other expenses, and a second tranche of an additional $100.0 million, which funded in January 2026 with net proceeds received of $98.5 million after deducting fees and expenses.
The net proceeds were used, together with cash on hand, to fund the redemption of $250.0 million in aggregate of the 7.125% Senior Notes due 2026. On March 24, 2026, we made a voluntary prepayment of $53.6 million against the GoA Term Loan. On May 1, 2026, the GoA Term Loan Facility was amended to apply this prepayment in full satisfaction of the scheduled principal amount due on the first scheduled amortization payment date on June 30, 2026, and then ratably to all remaining scheduled principal payments of the outstanding loans. The amendment also deferred all future scheduled amortization payment dates in 2026, 2027 and 2028 such that they will now be due on October 1, January 1, April 1 and July 1 in each of 2026, 2027 and 2028. As a result of the amendment, there is only one remaining scheduled amortization payment in 2026 to be paid on October 1, 2026.
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.
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.
The GoA Term Loan Facility also 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. We were in compliance with the covenants, representations and warranties contained in the GoA Term Loan Facility as of the most recent assessment date.
GTA Nordic bonds
In January 2026 the Company issued $350.0 million of 11.250% senior secured bonds due 2031 in the Nordic market (the “GTA Nordic bonds”). In the first quarter of 2026, the Company used the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $249.8 million of the 7.750% Senior Notes pursuant to the Company’s cash tender offer announced on January 12, 2026 and open market repurchases, and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.
The GTA Nordic bonds mature in January 2031. Interest is payable semi-annually in arrears each July 29 and January 29, commencing on July 29, 2026. The GTA Nordic bonds were issued by Kosmos Energy GTA Holdings, a wholly-owned subsidiary of Kosmos Energy Ltd., and are fully and unconditionally guaranteed by the Company and the Company’s wholly-owned subsidiaries, Kosmos Energy Tortue Finance, Kosmos Energy Senegal, Kosmos Energy Investments Senegal Limited and Kosmos Energy Mauritania. The GTA Nordic bonds are also guaranteed on an unsecured basis by certain of the Company’s subsidiaries that also guarantee the Company’s existing senior unsecured notes.
22
At any time prior to July 29, 2028, the Company may, on any one or more occasions, redeem all or part of the GTA Nordic bonds at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a “make-whole” premium. On and after July 29, 2028, the Company may redeem all or part of the GTA Nordic bonds at the following redemption prices (expressed as a percentage of principal amount), plus accrued and unpaid interest, if any, on the notes redeemed:
Year | Percentage | |||||||
July 29, 2028 to, but not including, July 29, 2029 | 105.625 | % | ||||||
July 29, 2029 to, but not including, July 29, 2030 | 103.375 | % | ||||||
July 29, 2030 and thereafter | 100.000 | % | ||||||
If the Company’s shares are no longer listed on the New York Stock Exchange or upon the occurrence of a change of control event, as defined in the Bond Terms for the GTA Nordic bonds, each Nordic bondholder shall have a right to require that the Company repurchase all or some of the GTA Nordic bonds held by that Nordic bondholder (a “Put Option”) at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase. If more than 90% of the outstanding GTA Nordic bonds have been repurchased as a result of the exercise of the Put Option, the Company will be entitled to repurchase all the remaining GTA Nordic bonds at a price equal to 101% of the principal amount.
The Bond Terms governing the GTA Nordic bonds restrict the ability of Kosmos Energy GTA Holdings, Kosmos Energy Tortue Finance, Kosmos Energy Senegal, Kosmos Energy Investments Senegal Limited and Kosmos Energy Mauritania to, among other things: incur or guarantee additional indebtedness, create liens, sell assets, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations.
The Bond Terms governing the GTA Nordic bonds also require Kosmos Energy GTA Holdings to maintain certain financial covenants including:
•Minimum Liquidity (as defined in the Bond Terms) of not less than $17.5 million or 5% of the outstanding GTA Nordic bonds, whichever is greater; and
•an Asset Coverage Ratio (as defined in the Bond Terms) of at least 1.25x
We were in compliance with the financial covenants as of the most recent assessment date. The GTA Nordic bonds contains customary cross default provisions.
Principal Debt Repayments
At June 30, 2026, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:
| Payments Due by Year | |||||||||||||||||||||||||||||||||||||||||
| Total | 2026(2) | 2027 | 2028 | 2029 | 2030 | Thereafter | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Principal debt repayments(1) | $ | 2,719,676 | $ | 15,110 | $ | 304,848 | $ | 718,857 | $ | 430,861 | $ | 400,000 | $ | 850,000 | |||||||||||||||||||||||||||
__________________________________
(1)Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as of June 30, 2026 are based on our level of borrowings and our estimated future available borrowing base commitment levels in future periods. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
(2)Represents payments for the period July 1, 2026 through December 31, 2026.
23
Interest and other financing costs, net
Interest and other financing costs, net incurred during the periods is comprised of the following:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Interest expense | $ | 60,995 | $ | 55,825 | $ | 122,051 | $ | 111,671 | |||||||||||||||
| Amortization—deferred financing costs | 2,705 | 1,889 | 5,297 | 3,773 | |||||||||||||||||||
| Debt modifications and extinguishments | 136 | — | (1,081) | — | |||||||||||||||||||
| Capitalized interest | (2,229) | (4,316) | (4,096) | (8,510) | |||||||||||||||||||
| Deferred interest | (8,239) | 249 | (10,954) | (1,793) | |||||||||||||||||||
| Interest income | (8,265) | (7,158) | (16,140) | (15,253) | |||||||||||||||||||
| Other, net | 8,597 | 8,345 | 17,425 | 16,788 | |||||||||||||||||||
| Interest and other financing costs, net | $ | 53,700 | $ | 54,834 | $ | 112,502 | $ | 106,676 | |||||||||||||||
9. Derivative Financial Instruments
We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.
We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurement.
Oil Derivative Contracts
The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of June 30, 2026. 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 | ||||||||||||||||||||||||||||||||||||||||||
2026: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Three-way collars | Dated Brent | 1,000 | — | — | 50.00 | 60.00 | 75.51 | ||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Swaps(1) | Dated Brent | 500 | — | 72.46 | — | — | 100.00 | ||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Swaps(1) | Dated Brent | 1,000 | — | 69.70 | 55.00 | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Swaps(1) | NYMEX WTI | 750 | — | 64.83 | 50.00 | — | — | ||||||||||||||||||||||||||||||||||||||||||
2027: | ||||||||||||||||||||||||||||||||||||||||||||||||||
Jan - Dec | Three-way collars | Dated Brent | 2,000 | 0.40 | — | 47.50 | 60.00 | 75.00 | ||||||||||||||||||||||||||||||||||||||||||
Jan - Jun | Three-way collars | Dated Brent | 2,000 | 0.03 | — | 55.00 | 70.00 | 85.00 | ||||||||||||||||||||||||||||||||||||||||||
Jan - Dec | Three-way collars | NYMEX WTI | 1,000 | 0.50 | — | 55.00 | 70.00 | 90.00 | ||||||||||||||||||||||||||||||||||||||||||
__________________________________
(1)Includes option contracts sold to counterparties to enhance Swaps.
In July 2026, we entered into Dated Brent two-way collar contracts for 2.0 MMBbl from January 2027 through December 2027 with a weighted average floor price of $67.50 per barrel and a ceiling price of $90.00 per barrel.
24
The following tables disclose the Company’s derivative instruments as of June 30, 2026 and December 31, 2025, and gain/(loss) from derivatives during the three and six months ended June 30, 2026 and 2025, respectively:
| Estimated Fair Value | ||||||||||||||||||||
| Asset (Liability) | ||||||||||||||||||||
| Type of Contract | Balance Sheet Location | June 30, 2026 | December 31, 2025 | |||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Derivatives not designated as hedging instruments: | ||||||||||||||||||||
| Derivative assets: | ||||||||||||||||||||
| Commodity | Derivatives assets—current | $ | 459 | $ | 47,816 | |||||||||||||||
| Provisional sales contracts | Receivables: Oil and gas sales | 857 | — | |||||||||||||||||
| Commodity | Derivatives assets—long-term | 2,335 | 2,681 | |||||||||||||||||
| Derivative liabilities: | ||||||||||||||||||||
| Commodity | Derivatives liabilities—current | (11,633) | — | |||||||||||||||||
| Commodity | Derivatives liabilities—long-term | (5,129) | — | |||||||||||||||||
| Total derivatives not designated as hedging instruments | $ | (13,111) | $ | 50,497 | ||||||||||||||||
| Amount of Gain/(Loss) | Amount of Gain/(Loss) | |||||||||||||||||||||||||||||||
| Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||
| June 30, | June 30, | |||||||||||||||||||||||||||||||
| Type of Contract | Location of Gain/(Loss) | 2026 | 2025 | 2026 | 2025 | |||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
Derivatives not designated as hedging instruments: | ||||||||||||||||||||||||||||||||
Provisional sales contracts | Oil and gas revenue | $ | (11,126) | $ | (6,780) | $ | (62,105) | $ | (7,607) | |||||||||||||||||||||||
| Commodity | Derivatives, net | 51,809 | 21,566 | (200,187) | 14,834 | |||||||||||||||||||||||||||
Interest rate | Interest expense | — | 683 | — | 656 | |||||||||||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | 40,683 | $ | 15,469 | $ | (262,292) | $ | 7,883 | ||||||||||||||||||||||||
Offsetting of Derivative Assets and Derivative Liabilities
Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of June 30, 2026 and December 31, 2025, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.
10. Fair Value Measurements
In accordance with ASC 820 — Fair Value Measurement, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:
•Level 1 — quoted prices for identical assets or liabilities in active markets.
•Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.
•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.
25
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2026 and December 31, 2025, for each fair value hierarchy level:
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.
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 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.
Provisional Sales Contracts
The value attributable to provisional sales contracts derivative 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 date of sale.
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 contributes 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.
26
As of June 30, 2026, 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 June 30, 2026. 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 six months ended June 30, 2026 and 2025, we contributed $11.6 million and $11.5 million to the decommissioning trust fund, respectively.
The following table summarizes the cost and fair value, purchases, proceeds from the sale and maturities, and the unrealized gains (losses) for Kosmos’ portion of the investments in debt securities held by the decommissioning trust during the six months ended June 30, 2026 and 2025:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||
Type of Security | Purchases | Net Proceeds (1) | Unrealized Gain (Loss) | Purchases | Net Proceeds (1) | Unrealized Gain (Loss) | ||||||||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||||||||
| 2026 | ||||||||||||||||||||||||||||||||||||||
| Debt securities | $ | 209 | $ | — | $ | (18) | $ | 12,051 | $ | — | $ | (106) | ||||||||||||||||||||||||||
| Cash and cash equivalents | — | (7) | — | — | 1 | — | ||||||||||||||||||||||||||||||||
| Other(1) | — | 156 | — | — | 181 | — | ||||||||||||||||||||||||||||||||
| Total | $ | 209 | $ | 149 | $ | (18) | $ | 12,051 | $ | 182 | $ | (106) | ||||||||||||||||||||||||||
| 2025 | ||||||||||||||||||||||||||||||||||||||
| Debt securities | $ | 198 | $ | — | $ | 22 | $ | 12,406 | $ | — | $ | 131 | ||||||||||||||||||||||||||
| Cash and cash equivalents | — | 2 | — | — | (745) | — | ||||||||||||||||||||||||||||||||
| Other(1) | — | 23 | — | — | 166 | — | ||||||||||||||||||||||||||||||||
| Total | $ | 198 | $ | 25 | $ | 22 | $ | 12,406 | $ | (579) | $ | 131 | ||||||||||||||||||||||||||
(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 June 30, 2026 and December 31, 2025:
| June 30, 2026 | December 31, 2025 | |||||||||||||||||||||||||
Cost | Estimated Fair Value | Cost | Estimated Fair Value | |||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||
Less than 5 years | $ | 35,616 | $ | 35,652 | $ | 23,565 | $ | 23,707 | ||||||||||||||||||
5 years to 10 years | — | — | — | — | ||||||||||||||||||||||
Due after 10 years | — | — | — | — | ||||||||||||||||||||||
Total | $ | 35,616 | $ | 35,652 | $ | 23,565 | $ | 23,707 | ||||||||||||||||||
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Debt
The following table presents the carrying values and fair values at June 30, 2026 and December 31, 2025:
| June 30, 2026 | December 31, 2025 | ||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
7.125% Senior Notes | $ | — | $ | — | $ | 99,942 | $ | 99,303 | |||||||||||||||
7.750% Senior Notes | 99,747 | 99,456 | 348,757 | 321,394 | |||||||||||||||||||
7.500% Senior Notes | 398,825 | 381,313 | 398,426 | 270,125 | |||||||||||||||||||
8.750% Senior Notes | 495,866 | 409,555 | 495,564 | 283,575 | |||||||||||||||||||
3.125% Convertible Senior Notes | 393,864 | 293,572 | 393,097 | 172,704 | |||||||||||||||||||
11.250% Senior Secured Bonds | 350,000 | 359,482 | — | — | |||||||||||||||||||
| GoA Term Loan Facility | 196,429 | 196,429 | 150,000 | 150,000 | |||||||||||||||||||
| Facility | 773,000 | 773,000 | 1,200,000 | 1,200,000 | |||||||||||||||||||
| Total | $ | 2,707,731 | $ | 2,512,807 | $ | 3,085,786 | $ | 2,497,101 | |||||||||||||||
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, 3.125% Convertible Senior Notes and 11.250% Senior Secured Bonds are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the GoA Term Loan Facility and Facility 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 six months ended June 30, 2026 and 2025, 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.
28
11. Equity-based Compensation
Restricted Stock Units
We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the LTIP awards. We recorded compensation expense from awards granted under our LTIP of $8.1 million and $7.3 million during the three months ended June 30, 2026 and 2025, respectively, and $14.1 million and $15.7 million during the six months ended June 30, 2026 and 2025, respectively. The total tax benefit for the three months ended June 30, 2026 and 2025 was $0.9 million and $1.2 million, respectively, and $1.9 million and $2.6 million during the six months ended June 30, 2026 and 2025, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of $(0.1) million and $0.3 million for the three months ended June 30, 2026 and 2025, respectively, and $7.6 million and $3.4 million during the six months ended June 30, 2026 and 2025, respectively. The fair value of awards vested during the three months ended June 30, 2026 and 2025 was $2.0 million and $0.6 million, respectively, and $5.7 million and $19.7 million during the six months ended June 30, 2026 and 2025, 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 $1.94 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 1.3% to 4.2%.
The following table reflects the outstanding restricted stock units as of June 30, 2026:
| 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, 2025 | 5,073 | $ | 4.59 | 8,105 | $ | 8.43 | |||||||||||||||||
| Granted(1) | 5,275 | 1.26 | 4,238 | 1.96 | |||||||||||||||||||
| Forfeited(1) | (864) | 1.21 | (254) | 4.37 | |||||||||||||||||||
| Vested | (2,824) | 4.47 | (590) | 12.25 | |||||||||||||||||||
| Outstanding at June 30, 2026 | 6,660 | $ | 2.80 | 11,499 | $ | 4.26 | |||||||||||||||||
__________________________________
(1)The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.
As of June 30, 2026, total equity-based compensation to be recognized on unvested restricted stock units is $21.2 million over a weighted average period of 1.74 years. At June 30, 2026, the Company had approximately 11.9 million shares that remain available for issuance under the LTIP.
29
12. 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 (loss) before income taxes is composed of the following:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| United States | $ | 14,647 | $ | (43,691) | $ | (36,949) | $ | (104,461) | |||||||||||||||
Foreign (1) | 267,826 | (20,069) | 78,335 | (53,330) | |||||||||||||||||||
| Income (loss) before income taxes | $ | 282,473 | $ | (63,760) | $ | 41,386 | $ | (157,791) | |||||||||||||||
(1) Foreign tax expense includes amounts related to Ceiba and Okume Complex located in Block G offshore Equatorial Guinea through the date of sale in June 2026. See Note 3 - Acquisitions and Divestitures for additional information.
For the three months ended March 31, 2026 and 2025, our effective tax rate was 35% and (38)%, respectively. For the six months ended June 30, 2026 and 2025, our effective tax rate was 199% and (26)%, respectively. For the three and six months ended June 30, 2026 and 2025, our overall effective tax rate was 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.
•Jurisdictions that have a 0% statutory tax rate or that are exempt,
•Jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and
•Other non-deductible expenses
30
13. 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 | Six Months Ended | ||||||||||||||||||||||
| June 30, | June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||||||||
| Numerator: | |||||||||||||||||||||||
| Net income (loss) allocable to common stockholders | $ | 184,775 | $ | (87,740) | $ | (40,799) | $ | (198,346) | |||||||||||||||
| Denominator: | |||||||||||||||||||||||
| Weighted average number of shares outstanding: | |||||||||||||||||||||||
| Basic | 593,441 | 478,068 | 550,060 | 476,881 | |||||||||||||||||||
| Restricted stock units(1) | 11,272 | — | — | — | |||||||||||||||||||
Shares issuable assuming conversion of 3.125% Convertible Senior Notes(2) | — | — | — | — | |||||||||||||||||||
| Diluted | 604,713 | 478,068 | 550,060 | 476,881 | |||||||||||||||||||
| Net income (loss) per share: | |||||||||||||||||||||||
| Basic | $ | 0.31 | $ | (0.18) | $ | (0.07) | $ | (0.42) | |||||||||||||||
| Diluted | $ | 0.31 | $ | (0.18) | $ | (0.07) | $ | (0.42) | |||||||||||||||
__________________________________
(1)We excluded restricted stock units of 2.5 million and 5.2 million for the three months ended June 30, 2026 and 2025, respectively, and 17.1 million and 5.9 million for the six months ended June 30, 2026 and 2025, 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 June 30, 2026, 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.
On March 10, 2026 the Company launched and priced a registered underwritten public offering of 112.1 million shares of common stock, par value $0.01, resulting in net proceeds to Kosmos of approximately $206.4 million. The offering closed on March 12, 2026.
14. Commitments and Contingencies
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes that the likelihood of an unfavorable outcome having a material impact is neither reasonably possible nor probable of occurring.
As of June 30, 2026, we have a commitment to drill a minimum of ten development wells under the amended Jubilee plan of development as part of the license extensions of WCTP and DT Petroleum Agreements in Ghana.
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 $111.0 million as of June 30, 2026, net to Kosmos, which will be funded annually by Kosmos over an estimated fourteen year period.
Performance Obligations
As of June 30, 2026 and December 31, 2025, the Company had performance and supplemental bonds totaling $150.5 million and $151.6 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.
31
Once the Tortue Phase 1 SPA Commercial Operations Date was achieved in February 2026, 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.
In February 2026, Tullow, as Operator of the TEN partnership, executed the final Sale and Purchase Agreement enabling the partnership to acquire the TEN FPSO from MODEC, Inc. at the end of its current lease in 2027 for a gross purchase price of $205.0 million. We have a commitment to Tullow for our proportionate share of the gross purchase price.
15. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
| June 30, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
| Accrued liabilities: | |||||||||||
| Exploration, development and production | $ | 43,793 | $ | 57,007 | |||||||
Revenue payable | 18,862 | 69,273 | |||||||||
Current asset retirement obligations | 9,767 | 10,481 | |||||||||
Finance lease liability | 73,203 | — | |||||||||
| General and administrative expenses | 23,460 | 4,916 | |||||||||
| Interest | 91,427 | 67,830 | |||||||||
| Income taxes | 51,596 | 16,050 | |||||||||
| Taxes other than income | 2,209 | 1,305 | |||||||||
| Derivatives | 14,921 | 125 | |||||||||
| Other | 14,641 | 10,622 | |||||||||
Total | $ | 343,879 | $ | 237,609 | |||||||
Asset Retirement Obligations
The following table summarizes the changes in the Company's asset retirement obligations as of and during the six months ended June 30, 2026:
| June 30, 2026 | |||||
| (In thousands) | |||||
| Asset retirement obligations: | |||||
| Beginning asset retirement obligations | $ | 337,497 | |||
| Liabilities incurred during period | 3,051 | ||||
| Liabilities settled during period | (143,166) | ||||
| Revisions in estimated retirement obligations | 242 | ||||
| Accretion expense | 15,587 | ||||
| Ending asset retirement obligations | $ | 213,211 | |||
The liabilities settled during 2026 primarily relate to the sale of the Ceiba and Okume Complex production assets located in Block G offshore Equatorial Guinea in June 2026. See Note 3 - Acquisitions and Divestitures.
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16. Business Segment Information
Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. For the three and six months ended June 30, 2026, the Company’s segment information is presented for four geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the Gulf of America. The Equatorial Guinea segment reflects the results of the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea through the date of sale in June 2026. See Note 3 - Acquisitions and Divestitures for additional information. 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(2) | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2026 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | 356,595 | $ | 47,161 | $ | 92,058 | $ | 111,439 | $ | — | $ | — | $ | 607,253 | |||||||||||||||||||||||||||
| Gain on sale of assets | — | 9,421 | — | — | — | — | 9,421 | ||||||||||||||||||||||||||||||||||
| Other income, net | 361 | — | — | 46 | 131 | (177) | 361 | ||||||||||||||||||||||||||||||||||
| Total revenues and other income | 356,956 | 56,582 | 92,058 | 111,485 | 131 | (177) | 617,035 | ||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | 59,031 | 25,244 | 65,827 | 29,327 | — | — | 179,429 | ||||||||||||||||||||||||||||||||||
| Exploration expenses | (3) | 146 | 238 | 2,653 | 163 | — | 3,197 | ||||||||||||||||||||||||||||||||||
| General and administrative | 3,227 | 1,003 | 2,710 | 4,886 | 41,984 | (34,547) | 19,263 | ||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | 54,075 | 2,611 | 35,221 | 27,740 | 854 | — | 120,501 | ||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | 10,803 | (22) | 8,379 | 1,320 | 33,220 | — | 53,700 | ||||||||||||||||||||||||||||||||||
| Derivatives, net | — | — | — | — | (51,809) | — | (51,809) | ||||||||||||||||||||||||||||||||||
| Other expenses, net | (21,970) | (226) | 1,352 | (4,662) | 1,417 | 34,370 | 10,281 | ||||||||||||||||||||||||||||||||||
| Total costs and expenses | 105,163 | 28,756 | 113,727 | 61,264 | 25,829 | (177) | 334,562 | ||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | 251,793 | 27,826 | (21,669) | 50,221 | (25,698) | — | 282,473 | ||||||||||||||||||||||||||||||||||
| Income tax expense | 91,498 | 5,093 | 9 | 70 | 1,028 | — | 97,698 | ||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 160,295 | $ | 22,733 | $ | (21,678) | $ | 50,151 | $ | (26,726) | $ | — | $ | 184,775 | |||||||||||||||||||||||||||
| Consolidated capital expenditures | $ | 70,494 | $ | 2,090 | $ | 3,216 | $ | 28,382 | $ | 870 | $ | — | $ | 105,052 | |||||||||||||||||||||||||||
33
| Ghana | Equatorial Guinea(2) | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Six months ended June 30, 2026 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | 557,859 | $ | 69,556 | $ | 144,325 | $ | 206,241 | $ | — | $ | — | $ | 977,981 | |||||||||||||||||||||||||||
| Gain on sale of assets | — | 9,421 | — | — | — | — | 9,421 | ||||||||||||||||||||||||||||||||||
| Other income, net | 530 | — | — | 103 | 291,492 | (291,595) | 530 | ||||||||||||||||||||||||||||||||||
| Total revenues and other income | 558,389 | 78,977 | 144,325 | 206,344 | 291,492 | (291,595) | 987,932 | ||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | 87,455 | 40,097 | 121,168 | 61,304 | — | — | 310,024 | ||||||||||||||||||||||||||||||||||
| Exploration expenses | — | 1,260 | 574 | 6,667 | 14,440 | — | 22,941 | ||||||||||||||||||||||||||||||||||
| General and administrative | 7,167 | 2,468 | 5,420 | 10,690 | 95,198 | (73,970) | 46,973 | ||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | 107,592 | 6,732 | 66,017 | 59,026 | 1,007 | — | 240,374 | ||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | 22,566 | (57) | 13,960 | 3,694 | 72,339 | — | 112,502 | ||||||||||||||||||||||||||||||||||
| Derivatives, net | — | — | — | — | 200,187 | — | 200,187 | ||||||||||||||||||||||||||||||||||
| Other expenses, net | 132,978 | 67,842 | 2,077 | 25,829 | 2,444 | (217,625) | 13,545 | ||||||||||||||||||||||||||||||||||
| Total costs and expenses | 357,758 | 118,342 | 209,216 | 167,210 | 385,615 | (291,595) | 946,546 | ||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | 200,631 | (39,365) | (64,891) | 39,134 | (94,123) | — | 41,386 | ||||||||||||||||||||||||||||||||||
Income tax expense (benefit) | 73,950 | 5,743 | 9 | 71 | 2,412 | — | 82,185 | ||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 126,681 | $ | (45,108) | $ | (64,900) | $ | 39,063 | $ | (96,535) | $ | — | $ | (40,799) | |||||||||||||||||||||||||||
| Consolidated capital expenditures, net | $ | 140,105 | $ | 2,599 | $ | 5,266 | $ | 46,907 | $ | 1,655 | $ | — | $ | 196,532 | |||||||||||||||||||||||||||
| As of June 30, 2026 | |||||||||||||||||||||||||||||||||||||||||
| Property and equipment, net | $ | 1,001,641 | $ | 13,999 | $ | 1,846,885 | $ | 487,042 | $ | 1,959 | $ | — | $ | 3,351,526 | |||||||||||||||||||||||||||
| Total assets | $ | 3,429,540 | $ | 132,939 | $ | 6,326,648 | $ | 3,884,596 | $ | 29,688,971 | $ | (39,152,547) | $ | 4,310,147 | |||||||||||||||||||||||||||
______________________________________
(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.
(2)In June 2026, the Company completed the disposition of its interests in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. The operating results of the Equatorial Guinea segment are included in the Company's consolidated results through the date of sale in June 2026. The disposition did not qualify for discontinued operations presentation. See Note 3 - Acquisitions and Divestitures for additional information.
34
Ghana | Equatorial Guinea(2) | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
(In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Three months ended June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | 204,706 | $ | 64,590 | $ | 20,239 | $ | 103,100 | $ | — | $ | — | $ | 392,635 | |||||||||||||||||||||||||||
| Gain on sale of assets | — | — | — | 600 | — | — | 600 | ||||||||||||||||||||||||||||||||||
| Other income, net | 246 | — | — | 219 | 13,880 | (14,062) | 283 | ||||||||||||||||||||||||||||||||||
| Total revenues and other income | 204,952 | 64,590 | 20,239 | 103,919 | 13,880 | (14,062) | 393,518 | ||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | 95,357 | 39,957 | 69,141 | 38,663 | — | — | 243,118 | ||||||||||||||||||||||||||||||||||
| Exploration expenses | 24 | (892) | 2,119 | 2,649 | 169 | — | 4,069 | ||||||||||||||||||||||||||||||||||
| General and administrative | 2,904 | 1,150 | 2,575 | 3,269 | 44,804 | (35,628) | 19,074 | ||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | 43,624 | 27,468 | 12,677 | 67,364 | 135 | — | 151,268 | ||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | 13,242 | (62) | 5,416 | (2,141) | 38,379 | — | 54,834 | ||||||||||||||||||||||||||||||||||
| Derivatives, net | — | — | — | — | (21,566) | — | (21,566) | ||||||||||||||||||||||||||||||||||
| Other expenses, net | (11,084) | (6,842) | 433 | 1,915 | 493 | 21,566 | 6,481 | ||||||||||||||||||||||||||||||||||
| Total costs and expenses | 144,067 | 60,779 | 92,361 | 111,719 | 62,414 | (14,062) | 457,278 | ||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | 60,885 | 3,811 | (72,122) | (7,800) | (48,534) | — | (63,760) | ||||||||||||||||||||||||||||||||||
Income tax expense (benefit) | 21,993 | 1,493 | — | 97 | 397 | — | 23,980 | ||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 38,892 | $ | 2,318 | $ | (72,122) | $ | (7,897) | $ | (48,931) | $ | — | $ | (87,740) | |||||||||||||||||||||||||||
| Consolidated capital expenditures, net | $ | 37,738 | $ | 3,914 | $ | 13,105 | $ | 31,181 | $ | 169 | $ | — | $ | 86,107 | |||||||||||||||||||||||||||
35
Ghana | Equatorial Guinea(2) | Mauritania/Senegal | Gulf of America | Corporate & Other | Eliminations | Total | |||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Six months ended June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenue | $ | 355,959 | $ | 98,997 | $ | 22,936 | $ | 204,878 | $ | — | $ | — | $ | 682,770 | |||||||||||||||||||||||||||
| Gain on sale of assets | — | — | — | 600 | — | — | 600 | ||||||||||||||||||||||||||||||||||
| Other income, net | 498 | — | — | 708 | 60,671 | (61,298) | 579 | ||||||||||||||||||||||||||||||||||
| Total revenues and other income | 356,457 | 98,997 | 22,936 | 206,186 | 60,671 | (61,298) | 683,949 | ||||||||||||||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||||||||
| Oil and gas production | 136,668 | 56,935 | 127,242 | 89,581 | — | — | 410,426 | ||||||||||||||||||||||||||||||||||
| Exploration expenses | 70 | 1,469 | 3,737 | 7,145 | 1,317 | — | 13,738 | ||||||||||||||||||||||||||||||||||
| General and administrative | 6,189 | 2,970 | 5,103 | 8,453 | 98,746 | (76,132) | 45,329 | ||||||||||||||||||||||||||||||||||
| Depletion, depreciation and amortization | 88,440 | 42,568 | 15,595 | 125,039 | 293 | — | 271,935 | ||||||||||||||||||||||||||||||||||
| Interest and other financing costs, net(1) | 24,384 | (129) | 4,402 | (4,161) | 82,180 | — | 106,676 | ||||||||||||||||||||||||||||||||||
| Derivatives, net | — | — | — | — | (14,834) | — | (14,834) | ||||||||||||||||||||||||||||||||||
| Other expenses, net | (5,888) | (5,317) | 1,147 | 3,262 | 432 | 14,834 | 8,470 | ||||||||||||||||||||||||||||||||||
| Total costs and expenses | 249,863 | 98,496 | 157,226 | 229,319 | 168,134 | (61,298) | 841,740 | ||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | 106,594 | 501 | (134,290) | (23,133) | (107,463) | — | (157,791) | ||||||||||||||||||||||||||||||||||
Income tax expense (benefit) | 38,669 | 892 | — | (14) | 1,008 | — | 40,555 | ||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 67,925 | $ | (391) | $ | (134,290) | $ | (23,119) | $ | (108,471) | $ | — | $ | (198,346) | |||||||||||||||||||||||||||
| Consolidated capital expenditures, net | $ | 56,696 | $ | 2,557 | $ | 62,118 | $ | 49,513 | $ | 1,411 | $ | — | $ | 172,295 | |||||||||||||||||||||||||||
| As of June 30, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Property and equipment, net | $ | 961,336 | $ | 446,405 | $ | 2,106,488 | $ | 827,437 | $ | 16,146 | $ | — | $ | 4,357,812 | |||||||||||||||||||||||||||
| Total assets | $ | 3,644,403 | $ | 2,458,795 | $ | 3,352,428 | $ | 4,112,600 | $ | 25,932,829 | $ | (34,288,049) | $ | 5,213,006 | |||||||||||||||||||||||||||
______________________________________
(1)Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.
(2)In June 2026, the Company completed the disposition of its interests in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. The disposition did not qualify for discontinued operations presentation. See Note 3 - Acquisitions and Divestitures for additional information.
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| Six Months Ended June 30, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands) | |||||||||||
| Consolidated capital expenditures: | |||||||||||
| Consolidated Statements of Cash Flows - Investing activities: | |||||||||||
| Oil and gas assets | $ | 163,477 | $ | 172,766 | |||||||
| Consolidated Statement of Cash Flows - Financing activities: | |||||||||||
| Financing lease | 14,951 | — | |||||||||
| Adjustments: | |||||||||||
| Changes in capital accruals | 5,473 | (5,910) | |||||||||
| Exploration expense, excluding unsuccessful well costs and leasehold impairments(1) | 8,982 | 13,577 | |||||||||
| Capitalized interest | (4,096) | (8,510) | |||||||||
| Other | 7,745 | 372 | |||||||||
| Total consolidated capital expenditures, net | $ | 196,532 | $ | 172,295 | |||||||
______________________________________
(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, 2025, 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
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, 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.
Recent Developments
Corporate
In April 2026, during the Spring 2026 redetermination, the Company’s lending syndicate approved a borrowing base at approximately $1.25 billion for the Facility. Following the closing of the sale of all our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea on June 16, 2026, the Company’s production assets in Equatorial Guinea are no longer included in the borrowing base amount, and, as agreed with the lending syndicate, the borrowing base has been reduced to approximately $1.2 billion.
Ghana
During the second quarter of 2026, Ghana production averaged approximately 105,700 Boepd gross (36,300 Boepd net). Two full Jubilee cargo liftings and one TEN lifting took place in the second quarter of 2026. A third Jubilee cargo began lifting on the last day of the quarter and was completed on July 2, 2026.
Jubilee development drilling continued to progress with a total of four producer wells successfully brought online during the year through the end of July 2026. To complete this year’s development drilling campaign, the final producer well is expected online in the coming days and a water injector well is expected online around the end of the third quarter of 2026.
Gulf of America
Production from the Gulf of America averaged approximately 14,300 Boepd net (~83% oil) for the second quarter of 2026.
On Tiberius, Kosmos (operator) continues to progress the development with our partners. We achieved a final investment decision in March 2026 with first oil targeted in the second half of 2028. Kosmos successfully completed a highly competitive farm-out process in July, with Navitas becoming a 33.33% partner in the project alongside Kosmos (33.34%) and Occidental (33.33%, owner/operator of the host facility). The consideration for the farm-down is a mix of upfront cash, carry for future development capital expenditure, which is expected to cover Kosmos’ spend on the project through 2026 into mid-2027 and future milestone payments.
At Winterfell, the partnership spud Winterfell-5 in April 2026. Winterfell-5 was designed as a twin well to Winterfell-3 in order to restore production from the Winterfell-3 fault block. The Winterfell-5 well was temporarily abandoned in July 2026 by the operator due to challenges experienced during drilling operations arising from issues with the production casing. The partnership is currently evaluating the cause of the casing issue in order to restore production from the Winterfell-3 fault block. In April 2026, production from the Winterfell-2 was shut-in pending a future intervention. The Company maintains
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insurance coverage that it expects will offset a significant portion of any remediation costs that may be incurred to restore the Winterfell-2 well to normal operations.
Equatorial Guinea
On June 16, 2026, we completed the sale of all our 40.4% participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea to a subsidiary of Panoro Energy ASA. Pursuant to the terms of the Sale and Purchase Agreement, Kosmos received final cash consideration of approximately $127.0 million, based on the initial purchase price of $180.0 million reduced by certain purchase price adjustments totaling approximately $53.0 million. We are also entitled to future contingent consideration of up to $39.5 million, comprised of $12.5 million linked to future production performance at the Ceiba field and $9.0 million payable in each of the years 2027, 2028 and 2029, subject to certain Block G production and oil price thresholds. Upon closing, the Company recognized a gain on sale of assets of approximately $9.4 million, representing the excess of net proceeds received over the carrying value of the disposal group. Operating results throughout this Form 10-Q continue to include the operating results of the Equatorial Guinea business through the date of sale.
Mauritania and Senegal
Greater Tortue Ahmeyim (GTA) Field
Production in Mauritania and Senegal from GTA averaged approximately 64,300 Boepd gross (15,700 Boepd net) in the second quarter of 2026. Nine gross LNG cargos and one gross condensate cargo lifted in the second quarter of 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, including the results related to the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea through the date of sale in June 2026. See Note 3 - Acquisitions and Divestitures for additional information. Certain operating results and statistics for the three and six months ended June 30, 2026 and 2025 are included in the following tables:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| (In thousands, except per volume data) | |||||||||||||||||||||||
| Sales volumes: | |||||||||||||||||||||||
| Oil (MBbl) | 4,571 | 5,363 | 8,985 | 9,023 | |||||||||||||||||||
| Gas (MMcf) | 12,272 | 7,120 | 25,021 | 11,292 | |||||||||||||||||||
| NGL (MBbl) | 389 | 113 | 492 | 204 | |||||||||||||||||||
| Total (MBoe) | 7,005 | 6,663 | 13,647 | 11,109 | |||||||||||||||||||
| Total (Boepd) | 76,982 | 73,216 | 75,399 | 61,376 | |||||||||||||||||||
| Revenues: | |||||||||||||||||||||||
| Oil sales | $ | 496,291 | $ | 354,518 | $ | 793,302 | $ | 624,923 | |||||||||||||||
| Gas sales | 83,601 | 36,049 | 155,705 | 53,678 | |||||||||||||||||||
| NGL sales | 27,361 | 2,068 | 28,974 | 4,169 | |||||||||||||||||||
| Total oil and gas revenue | $ | 607,253 | $ | 392,635 | $ | 977,981 | $ | 682,770 | |||||||||||||||
| Average oil sales price per Bbl | $ | 108.57 | $ | 66.10 | $ | 88.29 | $ | 69.26 | |||||||||||||||
| Average gas sales price per Mcf | 6.81 | 5.06 | 6.22 | 4.75 | |||||||||||||||||||
| Average NGL sales price per Bbl | 70.34 | 18.30 | 58.89 | 20.44 | |||||||||||||||||||
| Average total sales price per Boe | $ | 86.68 | $ | 58.93 | $ | 71.66 | $ | 61.46 | |||||||||||||||
| Costs: | |||||||||||||||||||||||
| Oil and gas production, excluding workovers | $ | 178,018 | $ | 241,306 | $ | 305,974 | $ | 394,933 | |||||||||||||||
| Oil and gas production, workovers | 1,411 | 1,812 | 4,050 | 15,493 | |||||||||||||||||||
| Total oil and gas production costs | $ | 179,429 | (1) | $ | 243,118 | (1) | $ | 310,024 | (1) | $ | 410,426 | ||||||||||||
| Depletion, depreciation and amortization | $ | 120,501 | $ | 151,268 | $ | 240,374 | $ | 271,935 | |||||||||||||||
| Average cost per Boe: | |||||||||||||||||||||||
| Oil and gas production, excluding workovers | $ | 25.41 | $ | 36.22 | $ | 22.42 | $ | 35.55 | |||||||||||||||
| Oil and gas production, workovers | 0.20 | 0.27 | 0.30 | 1.39 | |||||||||||||||||||
| Total oil and gas production costs | $ | 25.61 | (1) | $ | 36.49 | (1) | $ | 22.72 | (1) | $ | 36.94 | ||||||||||||
| Depletion, depreciation and amortization | 17.20 | 22.70 | 17.61 | 24.48 | |||||||||||||||||||
| Total | $ | 42.81 | $ | 59.19 | $ | 40.33 | $ | 61.42 | |||||||||||||||
______________________________________
(1)Substantially all NGLs and natural gas sales in Ghana and the Gulf of America are associated production from our oil wells and, therefore, production costs metrics are presented under a common unit of measure. In Mauritania and Senegal, all condensate sales and LNG sales are associated production from our gas wells and the first LNG cargo was successfully completed in April 2025. Oil and gas production costs related to LNG production at the GTA Phase 1 project were $65.8 million and $69.1 million for the three months ended June 30, 2026 and 2025, respectively, and $121.2 million and $127.2 million for the six months ended June 30, 2026 and 2025, respectively. Production costs per Mcfe in Mauritania and Senegal was $6.98 and $23.13 for the three months ended June 30, 2026 and 2025, respectively, and $6.89 and $36.95 for the six months ended June 30, 2026 and 2025. Mauritania and Senegal LNG sales are presented as gas sales in the table.
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The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of June 30, 2026:
| Actively Drilling or | Wells Suspended or | ||||||||||||||||||||||||||||||||||||||||||||||
| Completing | Waiting on Completion | ||||||||||||||||||||||||||||||||||||||||||||||
| Exploration | Development | Exploration | Development | ||||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||||||||
| Ghana | |||||||||||||||||||||||||||||||||||||||||||||||
| Jubilee Unit | — | — | 1 | 0.39 | — | — | 5 | 1.93 | |||||||||||||||||||||||||||||||||||||||
| TEN | — | — | — | — | — | — | 5 | 1.02 | |||||||||||||||||||||||||||||||||||||||
Gulf of America | |||||||||||||||||||||||||||||||||||||||||||||||
| Winterfell | — | — | 1 | 0.25 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
Tiberius | — | — | — | — | 1 | 0.50 | — | — | |||||||||||||||||||||||||||||||||||||||
| Mauritania / Senegal | |||||||||||||||||||||||||||||||||||||||||||||||
Greater Tortue Ahmeyim | — | — | — | — | 1 | 0.27 | — | — | |||||||||||||||||||||||||||||||||||||||
| Total | — | — | 2 | 0.64 | 2 | 0.77 | 10 | 2.95 | |||||||||||||||||||||||||||||||||||||||
The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results including the results related to the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea through the date of sale in June 2026. See Note 3 - Acquisitions and Divestitures for additional information. The following discussion may not be indicative of future results.
Three months ended June 30, 2026 compared to three months ended June 30, 2025
| Three Months Ended | |||||||||||||||||
| June 30, | Increase | ||||||||||||||||
| 2026 | 2025 | (Decrease) | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Oil and gas revenue | $ | 607,253 | $ | 392,635 | $ | 214,618 | |||||||||||
| Gain on sale of assets | 9,421 | 600 | 8,821 | ||||||||||||||
| Other income, net | 361 | 283 | 78 | ||||||||||||||
| Total revenues and other income | 617,035 | 393,518 | 223,517 | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Oil and gas production | 179,429 | 243,118 | (63,689) | ||||||||||||||
| Exploration expenses | 3,197 | 4,069 | (872) | ||||||||||||||
| General and administrative | 19,263 | 19,074 | 189 | ||||||||||||||
| Depletion, depreciation and amortization | 120,501 | 151,268 | (30,767) | ||||||||||||||
| Interest and other financing costs, net | 53,700 | 54,834 | (1,134) | ||||||||||||||
| Derivatives, net | (51,809) | (21,566) | (30,243) | ||||||||||||||
| Other expenses, net | 10,281 | 6,481 | 3,800 | ||||||||||||||
| Total costs and expenses | 334,562 | 457,278 | (122,716) | ||||||||||||||
| Income (loss) before income taxes | 282,473 | (63,760) | 346,233 | ||||||||||||||
| Income tax expense | 97,698 | 23,980 | 73,718 | ||||||||||||||
| Net income (loss) | $ | 184,775 | $ | (87,740) | $ | 272,515 | |||||||||||
Oil and gas revenue. Oil and gas revenue increased by $214.6 million during the three months ended June 30, 2026 as compared to the three months ended June 30, 2025 primarily as a result of higher production and sales volumes at Jubilee and GTA and higher average realized oil and gas prices during the three months ended June 30, 2026, partially offset by lower sales volumes in Equatorial Guinea and in the Gulf of America business unit. We sold 7,005 MBoe at an average realized price per
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barrel equivalent of $86.68 during the three months ended June 30, 2026 and 6,663 MBoe at an average realized price per barrel equivalent of $58.93 during the three months ended June 30, 2025.
Oil and gas production. Oil and gas production costs decreased by $63.7 million during the three months ended June 30, 2026 as compared to the three months ended June 30, 2025. Oil and gas production costs are lower in 2026 across all of our business units primarily as a result of lower routine operating costs in Ghana and GTA.
Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased by $30.8 million during the three months ended June 30, 2026, as compared with the three months ended June 30, 2025 primarily as a result of lower depletion rates per Boe at Jubilee and in the Gulf of America business unit and no depletion recorded on the Equatorial Guinea assets sold during the quarter, partially offset by higher sales volumes at Jubilee and GTA.
Derivatives, net. During the three months ended June 30, 2026 and 2025, we recorded a gain of $51.8 million and a gain of $21.6 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 June 30, 2026 and 2025, 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%.
Six months ended June 30, 2026 compared to six months ended June 30, 2025
| Six Months Ended | |||||||||||||||||
| June 30, | Increase | ||||||||||||||||
| 2026 | 2025 | (Decrease) | |||||||||||||||
(In thousands) | |||||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Oil and gas revenue | $ | 977,981 | $ | 682,770 | $ | 295,211 | |||||||||||
| Gain on sale of assets | 9,421 | 600 | 8,821 | ||||||||||||||
| Other income, net | 530 | 579 | (49) | ||||||||||||||
| Total revenues and other income | 987,932 | 683,949 | 303,983 | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Oil and gas production | 310,024 | 410,426 | (100,402) | ||||||||||||||
| Exploration expenses | 22,941 | 13,738 | 9,203 | ||||||||||||||
| General and administrative | 46,973 | 45,329 | 1,644 | ||||||||||||||
| Depletion, depreciation and amortization | 240,374 | 271,935 | (31,561) | ||||||||||||||
| Interest and other financing costs, net | 112,502 | 106,676 | 5,826 | ||||||||||||||
| Derivatives, net | 200,187 | (14,834) | 215,021 | ||||||||||||||
| Other expenses, net | 13,545 | 8,470 | 5,075 | ||||||||||||||
| Total costs and expenses | 946,546 | 841,740 | 104,806 | ||||||||||||||
| Income (loss) before income taxes | 41,386 | (157,791) | 199,177 | ||||||||||||||
| Income tax expense | 82,185 | 40,555 | 41,630 | ||||||||||||||
| Net income (loss) | $ | (40,799) | $ | (198,346) | $ | 157,547 | |||||||||||
Oil and gas revenue. Oil and gas revenue increased by $295.2 million during the six months ended June 30, 2026, as compared to the six months ended June 30, 2025 primarily as a result of higher production and sales volumes at Jubilee and GTA and higher average realized oil and gas prices during the six months ended June 30, 2026, partially offset by lower sales volumes in Equatorial Guinea and in the Gulf of America business unit. We sold 13,647 MBoe at an average realized price per barrel equivalent of $71.66 during the six months ended June 30, 2026 and 11,109 MBoe at an average realized price per barrel equivalent of $61.46 during the six months ended June 30, 2025.
Oil and gas production. Oil and gas production costs decreased by $100.4 million during the six months ended June 30, 2026, as compared to the six months ended June 30, 2025. Oil and production costs are lower in 2026 across all of our
42
business units primarily as a result of lower routine operating costs in Ghana and GTA and decreased workover expense in our Gulf of America business unit.
Exploration expenses. Exploration expenses increased by $9.2 million during the six months ended June 30, 2026, as compared to the six months ended June 30, 2025 primarily as a result of the write-off of exploration leasehold costs during the first quarter of 2026, partially offset by decreased seismic, geological and geophysical studies and related costs for the six months ended June 30, 2026 as part of the Company’s focus on managing costs across our portfolio.
Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $31.6 million during the six months ended June 30, 2026, as compared with the six months ended June 30, 2025 primarily as a result of lower depletion rates per Boe across our portfolio and no depletion recorded on the Equatorial Guinea assets sold during the period, partially offset by higher sales volumes at Jubilee and GTA.
Interest and other financing costs, net. Interest and other financing costs, net increased $5.8 million during the six months ended June 30, 2026, compared with the six months ended June 30, 2025, primarily driven by higher interest rates on outstanding debt and lower capitalized interest in 2026.
Derivatives, net. During the six months ended June 30, 2026 and 2025, we recorded a loss of $200.2 million and a gain of $14.8 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 six months ended June 30, 2026 and 2025, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.
Liquidity and Capital Resources
We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to our strategy as a 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 is expected to support our remaining capital program for 2026.
As such, our capital budget for the second half of 2026 is based on our exploitation plans for our producing assets in Ghana, Mauritania, Senegal and the Gulf of America, and our development activities in the Gulf of America and in 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, natural gas and LNG and 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.
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Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the six months ended June 30, 2026 and 2025:
| Six Months Ended | |||||||||||
| June 30, | |||||||||||
| 2026 | 2025 | ||||||||||
| (In thousands) | |||||||||||
| Sources of cash, cash equivalents and restricted cash: | |||||||||||
| Net cash provided by operating activities | $ | 281,566 | $ | 126,280 | |||||||
| Borrowings under long-term debt | 124,167 | 200,000 | |||||||||
| Net proceeds from issuance of senior notes and bonds | 350,000 | — | |||||||||
| Net proceeds from issuance of common stock | 206,440 | — | |||||||||
| Proceeds on sale of assets | 127,034 | — | |||||||||
| 1,089,207 | 326,280 | ||||||||||
| Uses of cash, cash equivalents and restricted cash: | |||||||||||
| Oil and gas assets | 163,477 | 172,766 | |||||||||
Notes receivable and other investing activities | 11,598 | 86,791 | |||||||||
| Payments on long-term debt | 504,738 | 100,000 | |||||||||
| Repurchase and redemption of senior notes | 347,184 | — | |||||||||
Payments on finance lease | 14,951 | — | |||||||||
Other financing costs | 8,772 | 1 | |||||||||
| 1,050,720 | 359,558 | ||||||||||
| Increase (decrease) in cash, cash equivalents and restricted cash | $ | 38,487 | $ | (33,278) | |||||||
Net cash provided by operating activities. Net cash provided by operating activities for the six months ended June 30, 2026 was $281.6 million compared with net cash provided by operating activities for the six months ended June 30, 2025 of $126.3 million. The increase in cash provided by operating activities in the six months ended June 30, 2026 when compared to the same period in 2025 is primarily a result of higher production and sales volumes at Jubilee and GTA, higher average realized oil and gas prices, lower routine oil and gas production costs across all of our business units and decreased workover expense in our Gulf of America business unit.
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The following table presents our liquidity and financial position as of June 30, 2026 and December 31, 2025:
| June 30, 2026 | December 31, 2025 | ||||||||||
| (In thousands) | |||||||||||
Outstanding debt principal balances: | |||||||||||
Facility | $ | 773,000 | $ | 1,200,000 | |||||||
| 7.125% Senior Notes | — | 100,000 | |||||||||
7.750% Senior Notes | 99,973 | 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 | |||||||||
11.250% Senior Secured Bonds | 350,000 | — | |||||||||
| GoA Term Loan Facility | 196,429 | 150,000 | |||||||||
| Total long-term debt | 2,719,676 | 3,100,274 | |||||||||
| Cash and cash equivalents | 102,137 | 91,518 | |||||||||
Total restricted cash (1) | 54,094 | 26,226 | |||||||||
| Net debt(2) | $ | 2,563,445 | $ | 2,982,530 | |||||||
| Availability under the Facility | $ | 440,220 | $ | 150,000 | |||||||
| Availability under the GoA Term Loan Facility | $ | — | $ | 100,000 | |||||||
| Available borrowings plus cash and cash equivalents | $ | 542,357 | $ | 341,518 | |||||||
(1)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 7.750% 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. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance until the March 31, 2026 financial covenant test date. During the second quarter of 2026, the Facility lenders agreed to reduce the amount of the required restricted cash balance to three months of interest and fees until the September 30, 2026 financial covenant test date, after which the amount of the required restricted cash balance will be determined as usual. Our debt cover ratio for the most recent March 31, 2026 financial covenant test date exceeded 2.50x and the estimated restricted cash funding requirement is approximately $23.5 million. As of June 30, 2026, we have funded approximately $23.5 million into the debt service reserve account as required under the terms of the Facility.
(2)Excludes $73.2 million TEN FPSO finance lease liability. For purposes of the debt cover ratio calculation under the Facility, the finance lease liability is included in net debt.
Capital Expenditures and Investments
For our capital expenditure budget for the second half of 2026, we expect to incur capital costs as we:
• drill additional infill wells in Ghana and the Gulf of America; and
• advance development efforts in the Gulf of America and in Mauritania and Senegal.
We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our 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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2026 Capital Program
We estimate we will spend in aggregate around $350 million of capital for the year ending December 31, 2026, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:
•Approximately $290 million related to maintenance activities and infill development drilling across our producing Ghana and Gulf of America assets, including the TEN FPSO purchase payments;
•Approximately $60 million related to progressing our development programs in the Gulf of America and in Mauritania and Senegal and includes first half 2026 integrity spend in Equatorial Guinea.
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. In April 2026 during the Spring 2026 redetermination, the Company’s lending syndicate approved a borrowing base at approximately $1.25 billion. The borrowing base amount was 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. Following the closing of the sale of all our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea on June 16, 2026, the Company’s production assets in Equatorial Guinea are no longer included in the borrowing base amount, and, as agreed with the lending syndicate, the borrowing base has been reduced to approximately $1.2 billion. As of June 30, 2026, borrowings under the Facility totaled approximately $0.8 billion and the undrawn availability under the Facility was approximately $440 million. Final maturity of the Facility is December 31, 2029.
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 June 30, 2026, 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. Leverage was elevated in 2025 given lower oil prices and the impact of operation costs during the ramp-up of the GTA Phase 1 project combined with lower company production. As a result, in July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment made this covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returned to the originally agreed upon ratio of 3.50x for assessment dates thereafter. In February 2026, we further amended the debt cover ratio calculation through September 2026. This most recent amendment makes the covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.5x and 4.25x respectively, and for purposes of the financial covenant assessment date in March 2026, the calculation was made excluding the Company’s Mauritania and Senegal business unit. The debt cover ratio returns to the originally agreed upon ratio of 3.5x for assessment dates thereafter. 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 three series of senior notes outstanding as of June 30, 2026, which we collectively refer to as the “Senior Notes.” In January 2026, we used the net proceeds of $98.5 million from funding the second tranche of the GoA Term Loan Facility, together with cash on hand, to fund the redemption of the remaining $100.0 million of the 7.125% Senior Notes due 2026. Our 7.750% Senior Notes have an outstanding balance of $100.0 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 GoA Term Loan Facility and, with respect to certain of our subsidiaries that own our assets in Mauritania and Senegal, the GTA Nordic bonds). The GTA Nordic bonds are fully and unconditionally guaranteed by the Company, as well as the Company’s wholly-owned subsidiaries, Kosmos Energy Tortue Finance, Kosmos Energy Senegal, Kosmos Energy Investments Senegal Limited and Kosmos Energy Mauritania. The GTA Nordic bonds are also guaranteed on an unsecured basis by certain of the Company’s subsidiaries that also guarantee the Senior Notes on a senior, unsecured basis. 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
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
47
million, which was funded on October 1, 2025, and a second tranche of an additional $100.0 million, which was funded in January 2026. The net proceeds were used, together with cash on hand, to fund the redemption of $250.0 million in aggregate of the 7.125% Senior Notes due in 2026. On March 24, 2026, we made a voluntary prepayment of $53.6 million against the GoA Term Loan. On May 1, 2026, the GoA Term Loan Facility was amended to apply this prepayment in full satisfaction of the scheduled principal amount due on the first scheduled amortization payment date on June 30, 2026, and then ratably to all remaining scheduled principal payments of the outstanding loans. The amendment also deferred all future scheduled amortization payment dates in 2026, 2027 and 2028 such that they will now be due on October 1, January 1, April 1 and July 1 in each of 2026, 2027 and 2028. As a result of the amendment, there is only one remaining scheduled amortization payment in 2026 to be paid on October 1, 2026.
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.
GTA Nordic Bonds
In January 2026, we issued one series of senior secured GTA Nordic bonds totaling $350.0 million. Our 11.250% senior secured GTA Nordic bonds mature in January 2031, unless earlier redeemed or repurchased. Interest is payable semi-annually in arrears each July 29 and January 29, commencing July 29, 2026.
The GTA Nordic bonds were issued by Kosmos Energy GTA Holdings, a wholly-owned subsidiary of Kosmos Energy Ltd., and are fully and unconditionally guaranteed by the Company, as well as the Company’s wholly-owned subsidiaries, Kosmos Energy Tortue Finance, Kosmos Energy Senegal, Kosmos Energy Investments Senegal Limited and Kosmos Energy Mauritania. The GTA Nordic bonds are also guaranteed on an unsecured basis by certain of the Company’s subsidiaries that also guarantee the Company’s existing senior unsecured notes.
The Bond Terms governing the GTA Nordic bonds also require Kosmos Energy GTA Holdings to maintain certain financial covenants including:
•Minimum Liquidity (as defined in the Bond Terms) of not less than $17.5 million or 5% of the outstanding GTA Nordic bonds, whichever is greater; and
•an Asset Coverage Ratio (as defined in the Bond Terms) of at least 1.25x.
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Equity Issuance
On March 10, 2026, the Company launched and priced a registered underwritten public offering of 112.1 million shares of common stock, resulting in net proceeds to Kosmos of approximately $206.4 million. The offering closed on March 12, 2026.
Contractual Obligations
The following table summarizes by period the payments due for our estimated contractual obligations as of June 30, 2026, 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, | June 30, | |||||||||||||||||||||||||||||||||||||||||||||||||
| 2026(2) | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | 2026 | |||||||||||||||||||||||||||||||||||||||||||
| (In thousands, except percentages) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Fixed rate debt: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| 7.750% Senior Notes | $ | — | $ | 99,973 | $ | — | $ | — | $ | — | $ | — | $ | 99,973 | $ | 99,456 | ||||||||||||||||||||||||||||||||||
| 7.500% Senior Notes | — | — | 400,274 | — | — | — | 400,274 | 381,313 | ||||||||||||||||||||||||||||||||||||||||||
8.750% Senior Notes | — | — | — | — | — | 500,000 | 500,000 | 409,555 | ||||||||||||||||||||||||||||||||||||||||||
3.125% Convertible Senior Notes | — | — | — | — | 400,000 | — | 400,000 | 293,572 | ||||||||||||||||||||||||||||||||||||||||||
11.250% Senior Secured Bonds | — | — | — | — | — | 350,000 | 350,000 | 359,482 | ||||||||||||||||||||||||||||||||||||||||||
| Variable rate debt: | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average interest rate | 8.53 | % | 9.07 | % | 9.31 | % | 9.54 | % | — | % | — | % | ||||||||||||||||||||||||||||||||||||||
| Facility(1) | $ | — | $ | 144,436 | $ | 258,143 | $ | 370,421 | $ | — | $ | — | $ | 773,000 | $ | 773,000 | ||||||||||||||||||||||||||||||||||
GoA Term Loan Facility | 15,110 | 60,439 | 60,440 | 60,440 | — | — | 196,429 | 196,429 | ||||||||||||||||||||||||||||||||||||||||||
| Total principal debt repayments | $ | 15,110 | $ | 304,848 | $ | 718,857 | $ | 430,861 | $ | 400,000 | $ | 850,000 | $ | 2,719,676 | ||||||||||||||||||||||||||||||||||||
| Interest & commitment fee payments on long-term debt | 124,360 | 215,766 | 168,841 | 122,543 | 89,375 | 63,438 | 784,323 | |||||||||||||||||||||||||||||||||||||||||||
Operating leases(3) | 2,017 | 3,951 | 3,744 | 3,176 | — | — | 12,888 | |||||||||||||||||||||||||||||||||||||||||||
Finance lease | 24,504 | 52,514 | — | — | — | — | 77,018 | |||||||||||||||||||||||||||||||||||||||||||
Purchase obligations(4) | 12,682 | 21,270 | — | — | — | — | 33,952 | |||||||||||||||||||||||||||||||||||||||||||
Decommissioning Trust Funds(5) | — | 8,284 | 8,284 | 8,284 | 8,284 | 77,865 | 111,001 | |||||||||||||||||||||||||||||||||||||||||||
| Firm transportation commitments | 1,964 | 2,315 | — | — | — | — | 4,279 | |||||||||||||||||||||||||||||||||||||||||||
__________________________________
(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of June 30, 2026. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
(2)Represents the period July 1, 2026 through December 31, 2026.
(3)Primarily relates to corporate and foreign office leases.
(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 15 - 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 $111.0 million as of June 30, 2026, net to Kosmos, which will be funded annually by Kosmos over an estimated fourteen year period. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.
As of June 30, 2026, we have a commitment to drill a minimum of ten development wells under the amended Jubilee plan of development as part of the license extensions of WCTP and DT Petroleum Agreements in Ghana.
Once the Tortue Phase 1 SPA Commercial Operations Date was achieved in February 2026, 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
49
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, income taxes, estimates of proved oil and gas reserves, asset retirement obligations, impairment of long-lived assets, and acquisition accounting 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, 2025.
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 conflict in Iran and ongoing instability in the Middle East and Latin America, the continued war in Ukraine 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 liquified natural gas (“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;
•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;
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•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 9 — Derivative Financial Instruments and Note 10 — Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the six months ended June 30, 2026:
| Derivative Contracts Assets (Liabilities) | |||||
| Commodities | |||||
| (In thousands) | |||||
| Fair value of contracts outstanding as of December 31, 2025 | $ | 50,497 | |||
| Changes in contract fair value | (262,292) | ||||
| Contract maturities | 198,684 | ||||
| Fair value of contracts outstanding as of June 30, 2026 | $ | (13,111) | |||
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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 six months of 2026 ranged between $60.98 and $144.42 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during the first six months of 2026.
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 June 30, 2026. Volumes and weighted average prices are net of any offsetting derivatives entered into.
| Weighted Average Price per Bbl | Asset | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net Deferred | (Liability) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Premium | Fair Value at | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Payable/ | Sold | June 30, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Term | Type of Contract | Index | MBbl | (Receivable) | Swap | Put | Floor | Ceiling | 2026(2) | |||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2026: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Three-way collars | Dated Brent | 1,000 | — | — | 50.00 | 60.00 | 75.51 | (3,149) | |||||||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Swaps(1) | Dated Brent | 500 | — | 72.46 | — | — | 100.00 | (633) | |||||||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Swaps(1) | Dated Brent | 1,000 | — | 69.70 | 55.00 | — | — | (3,260) | |||||||||||||||||||||||||||||||||||||||||||||||
| Jul - Dec | Swaps(1) | NYMEX WTI | 750 | — | 64.83 | 50.00 | — | — | (3,183) | |||||||||||||||||||||||||||||||||||||||||||||||
| 2027: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Jan - Dec | Three-way collars | Dated Brent | 2,000 | $ | 0.40 | $ | — | $ | 47.50 | $ | 60.00 | $ | 75.00 | $ | (8,126) | |||||||||||||||||||||||||||||||||||||||||
Jan - Jun | Three-way collars | Dated Brent | 2,000 | 0.03 | — | 55.00 | 70.00 | 85.00 | 482 | |||||||||||||||||||||||||||||||||||||||||||||||
Jan - Dec | Three-way collars | NYMEX WTI | 1,000 | 0.50 | — | 55.00 | 70.00 | 90.00 | 3,901 | |||||||||||||||||||||||||||||||||||||||||||||||
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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 June 30, 2026.
In July 2026, we entered into Dated Brent two-way collar contracts for 2.0 MMBbl from January 2027 through December 2027 with a weighted average floor price of $67.50 per barrel and a ceiling price of $90.00 per barrel.
At June 30, 2026, our open commodity derivative instruments were in a net liability position of $14.0 million. As of June 30, 2026, a hypothetical 10% price increase in the oil price curves would decrease future pre-tax earnings by approximately $38.4 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $39.5 million.
Interest Rate Sensitivity
Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Facility and GoA Term Loan Facility as of June 30, 2026 total approximately $969.4 million. The current weighted average interest rate on this indebtedness was approximately 8.2%, and is subject to variable interest rates which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. If the floating market rate increased 10%, at this level of floating rate debt, we would pay an estimated additional $3.8 million interest expense per year on the Facility and GoA Term Loan Facility. 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.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of
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the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2026, 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, 2025.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information.
Rule 10b5-1 and Non Rule 10b5-1 Trading Arrangements
During the three months ended June 30, 2026, certain of our officers or directors adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K, as follows.
On May 27, 2026, Sir John Grant terminated a trading plan intended to satisfy the conditions under Rule 10b5-1(c) of the Exchange Act. Sir John Grant’s plan was previously adopted on March 4, 2026, for the sale of up to 43,466 shares of our common stock on June 3, 2026, 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. The plan was never utilized.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Kosmos Energy Ltd. | |||||||||||
| (Registrant) | |||||||||||
| Date | August 3, 2026 | /s/ NEAL D. SHAH | |||||||||
| Neal D. Shah | |||||||||||
| Senior Vice President and Chief Financial Officer | |||||||||||
| (Principal Financial Officer) | |||||||||||
Item 6. Exhibits
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10‑Q.
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INDEX OF EXHIBITS
| Exhibit Number | Description of Document | |||||||
| 31.1 | ||||||||
| 31.2 | ||||||||
| 32.1 | ||||||||
| 32.2 | ||||||||
| 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 | |||||||
___________________________________
†† Certain confidential portions of this Exhibit have been omitted pursuant to Item 601(b) of Regulation S-K because the identified confidential portions (i) are not material and (ii) would be competitively harmful if publicly disclosed.
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