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What changed in Kosmos Energy Ltd.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of Kosmos Energy Ltd.'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+428 added−444 removedSource: 10-K (2026-03-02) vs 10-K (2025-02-24)

Top changes in Kosmos Energy Ltd.'s 2025 10-K

428 paragraphs added · 444 removed · 296 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

136 edited+50 added−63 removed139 unchanged
Biggest changeGeographic Area Percentage of BOE Sales Volumes Sales Volumes (Net to Kosmos) Average Sales Price Production Depletion, depreciation and amortization per Boe Oil NGL Gas Total Oil NGL Gas Total Revenue costs per (MMBbls) (Bcf) (MMBoe) (per Bbl) (per Bcf) (per Boe) (in Thousands) Boe(2) For the year ended December 31, 2024 Jubilee 57 % 11.5 — 12.5 13.5 $ 80.30 — 3.80 $ 71.47 $ 967,673 $ 7.94 $ 14.84 TEN 4 % 1.0 — — 1.0 77.31 — — 77.31 76,889 57.14 2.43 Ghana 62 % 12.5 — 12.5 14.5 $ 80.06 $ — $ 3.80 $ 71.87 $ 1,044,562 $ 11.31 $ 14.00 Equatorial Guinea 14 % 3.4 — — 3.4 77.66 — — 77.66 260,675 40.63 19.42 Mauritania/Senegal — — — — — — — — — — — — Gulf of America 24 % 4.6 0.4 3.7 5.6 75.82 20.53 2.67 65.89 370,121 24.27 32.95 Total 100 % 20.5 0.4 16.2 23.5 $ 78.70 $ 20.53 $ 3.54 $ 71.27 $ 1,675,358 $ 22.57 (3) $ 19.43 For the year ended December 31, 2023 Jubilee 54 % 11.4 — 5.8 12.4 $ 83.33 — 3.74 $ 78.62 $ 974,627 $ 8.74 $ 17.30 TEN 7 % 1.0 — 3.9 1.7 85.72 — 0.64 53.06 87,855 40.40 15.97 Ghana 61 % 12.4 — 9.7 14.1 $ 83.52 $ — $ 2.48 $ 75.61 $ 1,062,482 $ 12.47 $ 17.15 Equatorial Guinea 15 % 3.4 — — 3.4 78.71 — — 78.71 267,494 33.67 15.23 Mauritania/Senegal — — — — — — — — — — — — Gulf of America 24 % 4.6 0.4 4.0 5.6 77.41 20.61 2.79 66.29 371,632 17.91 26.67 Total 100 % 20.4 0.4 13.7 23.1 $ 81.35 $ 20.61 $ 2.57 $ 73.80 $ 1,701,608 $ 16.92 $ 19.30 For the year ended December 31, 2022 Jubilee 49 % 11.4 — — 11.4 $ 101.23 — — $ 101.23 $ 1,162,416 $ 9.93 $ 20.32 TEN 9 % 2.0 — — 2.0 96.83 — — 96.83 188,546 47.48 28.57 Ghana(1) 58 % 13.4 — — 13.4 $ 100.59 $ — $ — $ 100.59 $ 1,350,962 $ 15.37 $ 21.52 Equatorial Guinea 14 % 3.3 — — 3.3 104.24 — — 104.24 346,783 27.23 16.16 Mauritania/Senegal — — — — — — — — — — — — Gulf of America 28 % 5.3 0.4 4.1 6.4 95.80 34.37 7.24 86.09 547,610 16.50 24.12 Total 100 % 22.0 0.4 4.1 23.1 $ 100.00 $ 34.37 $ 7.24 $ 97.13 $ 2,245,355 $ 17.39 $ 21.55 ______________________________________ (1) Our sales volumes during 2022 includes activity related to the interest pre-empted by Tullow prior to the March 17, 2022 closing date of the Tullow pre-emption transaction.
Biggest changeGeographic Area Percentage of BOE Sales Volumes Sales Volumes (Net to Kosmos) Average Sales Price Production Depletion, depreciation and amortization per Boe Oil NGL Gas Total Oil NGL Gas Total Revenue costs per (MMBbls) (Bcf) (MMBoe) (per Bbl) (per Bcf) (per Boe) (in Thousands) Boe(1) For the year ended December 31, 2025 Jubilee 42 % 7.6 — 11.8 9.5 $ 68.26 — 3.90 $ 59.02 $ 563,548 $ 11.83 $ 18.28 TEN 5 % 1.0 — 0.6 1.1 66.30 — 3.55 62.01 68,174 68.71 2.56 Ghana 47 % 8.6 — 12.4 10.6 $ 68.04 $ — $ 3.89 $ 59.33 $ 631,722 $ 17.70 $ 16.67 Equatorial Guinea 11 % 2.5 — — 2.5 66.41 — — 66.41 165,118 53.15 31.70 Mauritania|Senegal(3) 13 % — 0.2 16.2 2.9 — 56.03 6.66 40.91 117,197 82.92 23.43 Gulf of America 29 % 5.4 0.4 3.7 6.4 65.29 18.67 3.98 58.35 374,315 23.49 36.16 Total 100 % 16.5 0.6 32.3 22.4 $ 66.89 $ 29.75 $ 5.28 $ 57.48 $ 1,288,352 $ 31.63 (2) $ 24.84 For the year ended December 31, 2024 Jubilee 57 % 11.5 — 12.5 13.5 $ 80.30 — 3.80 $ 71.47 $ 967,673 $ 7.94 $ 14.84 TEN 4 % 1.0 — — 1.0 77.31 — — 77.31 76,889 57.14 2.43 Ghana 62 % 12.5 — 12.5 14.5 $ 80.06 $ — $ 3.80 $ 71.87 $ 1,044,562 $ 11.31 $ 14.00 Equatorial Guinea 14 % 3.4 — — 3.4 77.66 — — 77.66 260,675 40.63 19.42 Mauritania|Senegal — — — — — — — — — — — — Gulf of America 24 % 4.6 0.4 3.7 5.6 75.82 20.53 2.67 65.89 370,121 24.27 32.95 Total 100 % 20.5 0.4 16.2 23.5 $ 78.70 $ 20.53 $ 3.54 $ 71.27 $ 1,675,358 $ 22.57 (2) $ 19.43 For the year ended December 31, 2023 Jubilee 54 % 11.4 — 5.8 12.4 $ 83.33 — 3.74 $ 78.62 $ 974,627 $ 8.74 $ 17.30 TEN 7 % 1.0 — 3.9 1.7 85.72 — 0.64 53.06 87,855 40.40 15.97 Ghana 61 % 12.4 — 9.7 14.1 $ 83.52 $ — $ 2.48 $ 75.61 $ 1,062,482 $ 12.47 $ 17.15 Equatorial Guinea 15 % 3.4 — — 3.4 78.71 — — 78.71 267,494 33.67 15.23 Mauritania|Senegal — — — — — — — — — — — — Gulf of America 24 % 4.6 0.4 4.0 5.6 77.41 20.61 2.79 66.29 371,632 17.91 26.67 Total 100 % 20.4 0.4 13.7 23.1 $ 81.35 $ 20.61 $ 2.57 $ 73.80 $ 1,701,608 $ 16.92 $ 19.30 (4) ______________________________________ (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.
All domestic employees are awarded equity in the company as part of the total reward package, aligning employee reward with shareholder interest. We also offer a strong Employee Assistance Program (EAP), which offers 31 Table of Contents free and confidential assessments, counseling, and follow-up services to employees with personal and/or work-related mental health problems.
All domestic employees are awarded equity in the company as part of the total reward package, 31 Table of Contents aligning employee reward with shareholder interest. We also offer a strong Employee Assistance Program (EAP), which offers free and confidential assessments, counseling, and follow-up services to employees with personal and/or work-related mental health problems.
Culturally, we have an open, team‑oriented work environment that fosters entrepreneurial, creative and contrarian thinking. This approach enables us to fully consider and understand both risk and reward, as well as deliberately and collectively pursue ideas that create and maximize value and free cash flow. We are led by an experienced management team with a successful track record.
Culturally, we have an open, team‑oriented work environment that fosters entrepreneurial and creative thinking. This approach enables us to fully consider and understand both risk and reward, as well as deliberately and collectively pursue ideas that create and maximize value and free cash flow. We are led by an experienced management team with a successful track record.
The TEN PoD was designed to include an expandable subsea system that could provide for multiple phases. 15 Table of Contents Gulf of America In the Gulf of America, Kosmos maintains: (i) a portfolio of producing assets that we plan to continue to exploit, (ii) discovered resource opportunities, and (iii) a high-quality inventory of infrastructure-led exploration prospects across the DeSoto Canyon, Green Canyon, Keathley Canyon, Mississippi Canyon and Walker Ridge protraction areas.
The TEN PoD was designed to include an expandable subsea system that could provide for multiple phases. 16 Table of Contents Gulf of America In the Gulf of America, Kosmos maintains: (i) a portfolio of producing assets that we plan to continue to exploit, (ii) discovered resource opportunities, and (iii) a high-quality inventory of infrastructure-led exploration prospects across the DeSoto Canyon, Green Canyon, Keathley Canyon, Mississippi Canyon and Walker Ridge protraction areas.
During the year ended December 31, 2023, we had an overall proved undeveloped reserves decrease of 1.3 MMBoe due to several factors including the addition of sales gas and positive revision of future well forecasts based on improved performance of existing wells in Jubilee (+26.0 MMBoe), positive drilling results in Jubilee (+0.7 MMBoe), offset by a change to the partnership’s development work scope and forecasts of planned wells in TEN (-6.4 MMBoe), removal of one of the planned wells from the Okume drilling plan (-0.3 MMBoe), optimization of the timing of the Greater Tortue Ahmeyim Phase 1 project (+1.3 MMBoe), and changes to the recovery of several Gulf of America fields (-0.3 MMBoe).
During the year ended December 31, 2023, we had an overall proved undeveloped reserves decrease of 1.3 MMBoe due to several factors including the addition of sales gas and positive revision of future well forecasts based on improved performance of existing wells in Jubilee (+26.0 MMBoe), positive drilling results in Jubilee (+0.7 MMBoe), offset by a change to the partnership’s development work scope and forecasts of planned wells in TEN (-6.4 MMBoe), removal of one of the 22 Table of Contents planned wells from the Okume drilling plan (-0.3 MMBoe), optimization of the timing of the Greater Tortue Ahmeyim Phase 1 project (+1.3 MMBoe), and changes to the recovery of several Gulf of America fields (-0.3 MMBoe).
Estimated proved reserves Unless otherwise specifically identified in this report, the summary data with respect to our estimated net proved reserves for the years ended December 31, 2024, 2023 and 2022 has been prepared by RSC, our independent petroleum engineering firm for such years, in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
Estimated proved reserves Unless otherwise specifically identified in this report, the summary data with respect to our estimated net proved reserves for the years ended December 31, 2025, 2024 and 2023 has been prepared by RSC, our independent petroleum engineering firm for such years, in accordance with the rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.
The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report incorporated herein is Mr. Tosin Famurewa. Mr. Famurewa has been practicing consulting petroleum engineering at RSC since 2006. Mr. Famurewa is a Licensed Professional Engineer in the State of Texas (No. 100569) and has over 20 years of practical experience in petroleum engineering.
The RSC technical person primarily responsible for preparing the estimates set forth in the RSC reserves report incorporated herein is Mr. Tosin Famurewa. Mr. Famurewa has been practicing consulting petroleum engineering at RSC since 2006. Mr. Famurewa is a Licensed Professional Engineer in the State of Texas (No. 100569) and has over 25 years of practical experience in petroleum engineering.
The person primarily responsible for our Reservoir Engineering team is Mr. Douglas Trumbauer. Mr. Trumbauer is a Licensed Professional Engineer in the State of Texas (No. 78735) and has over 39 years of practical experience in petroleum engineering. He graduated from Pennsylvania State University in 1985 with a Bachelor of Science degree in Petroleum and Natural Gas Engineering. Mr.
The person primarily responsible for our Reservoir Engineering team is Mr. Douglas Trumbauer. Mr. Trumbauer is a Licensed Professional Engineer in the State of Texas (No. 78735) and has over 40 years of practical experience in petroleum engineering. He graduated from Pennsylvania State University in 1985 with a Bachelor of Science degree in Petroleum and Natural Gas Engineering. Mr.
These interest percentages are subject to redetermination of the participating interests in the Greater Tortue Ahmeyim Field pursuant to the terms of the GTA UUOA. (4) Our paying interest on development activities in the TEN Fields is 22.8%. (5) Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.
These interest percentages are subject to redetermination of the participating interests in the Greater Tortue Ahmeyim Field pursuant to the terms of the GTA UUOA. (5) Our paying interest on development activities in the TEN Fields is 22.8%. (6) Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.
There can be no assurance that the proved reserves will be produced within the periods indicated or prices and costs will remain constant. Independent petroleum engineers Ryder Scott Company, L.P. RSC, our independent petroleum engineers for the years ended December 31, 2024, 2023 and 2022, was established in 1937.
There can be no assurance that the proved reserves will be produced within the periods indicated or prices and costs will remain constant. Independent petroleum engineers Ryder Scott Company, L.P. RSC, our independent petroleum engineers for the years ended December 31, 2025, 2024 and 2023, was established in 1937.
The oil and gas industry as a whole has experienced continued volatility. Globally, the impact of Russia’s continued war in Ukraine, ongoing instability in the Middle East, a potential recession, inflationary pressures and other varying macroeconomic conditions has impacted supply and demand for oil and gas, which also resulted in significant variations in oil and gas prices.
The oil and gas industry as a whole has experienced continued volatility. Globally, the impact of Russia’s continued war in Ukraine, ongoing instability in the Middle East and Latin America, a potential recession, inflationary pressures and other varying macroeconomic conditions has impacted supply and demand for oil and gas, which also resulted in significant variations in oil and gas prices.
Our estimated reserves at December 31, 2024, 2023 and 2022 and related future net revenues and PV‑10 at December 31, 2024, 2023 and 2022 are taken from reports prepared by RSC, in accordance with petroleum engineering and evaluation principles which RSC believes are commonly used in the industry and definitions and current regulations established by the SEC.
Our estimated reserves at December 31, 2025, 2024 and 2023 and related future net revenues and PV‑10 at December 31, 2025, 2024 and 2023 are taken from reports prepared by RSC, in accordance with petroleum engineering and evaluation principles which RSC believes are commonly used in the industry and definitions and current regulations established by the SEC.
In 2024, we did not identify any cybersecurity threats that have materially affected or are reasonably likely to materially affect our business strategy, results of operations, or financial condition. However, despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced an undetected cybersecurity incident.
In 2025, we did not identify any cybersecurity threats that have materially affected or are reasonably likely to materially affect our business strategy, results of operations, or financial condition. However, despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced an undetected cybersecurity incident.
Such calculations at December 31, 2024 are based on costs in effect at December 31, 2024 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2024, adjusted for anticipated market premium, without giving effect to derivative transactions, and are held constant throughout the life of the assets.
Such calculations at December 31, 2025 are based on costs in effect at December 31, 2025 and the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the year ended December 31, 2025, adjusted for anticipated market premium, without giving effect to derivative transactions, and are held constant throughout the life of the assets.
For over 80 years, RSC has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits, appraisal of oil and gas properties including fair market value determination, reservoir simulation studies, enhanced recovery services, expert witness testimony, and management advisory services.
For over 85 years, RSC has provided services to the worldwide petroleum industry that include the issuance of reserves reports and audits, appraisal of oil and gas properties including fair market value determination, reservoir simulation studies, enhanced recovery services, expert witness testimony, and management advisory services.
RSC issued a report on our proved reserves at December 31, 2024, based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell hydrocarbons at their respective adjusted benchmark prices and certain levels of future capital expenditures.
RSC issued a report on our proved reserves at December 31, 2025, based upon its evaluation. RSC’s primary economic assumptions in estimates included an ability to sell hydrocarbons at their respective adjusted benchmark prices and certain levels of future capital expenditures.
Our Reservoir Engineering team is responsible for overseeing the preparation of our reserves estimates and has over 100 combined years of industry experience among them with positions of increasing responsibility in engineering and evaluations. Each member of our team holds a minimum of a Bachelor of Science degree in petroleum engineering or geology.
Our Reservoir Engineering team is responsible for overseeing the preparation of our reserves estimates and has over 80 combined years of industry experience among them with positions of increasing responsibility in engineering and evaluations. Each member of our team holds a minimum of a Bachelor of Science degree in petroleum engineering or geology.
After the elections, our interest in the exploration areas of Block C8 offshore Mauritania and in Saint Louis Offshore Profound offshore Senegal are unchanged, however, our interest in the Greater Tortue Ahmeyim Unit is now 26.8% in Mauritania and 26.7% in Senegal and is subject to redetermination of the participating interests pursuant to the terms of the GTA UUOA.
After the elections, our interest in the exploration areas of Block C8 offshore Mauritania and in Saint Louis Offshore Profound offshore Senegal were unchanged, however, our interest in the Greater Tortue Ahmeyim Unit is now 26.8% in Mauritania and 26.7% in Senegal and is subject to redetermination of the participating interests pursuant to the terms of the GTA UUOA.
Our management team members average over 26 years of industry experience and have participated in discovering, developing, and maximizing the value of multiple large-scale upstream projects around the world. Our experience, industry relationships and technical expertise are our core competitive strengths and are crucial to our success.
Our management team members average over 27 years of industry experience and have participated in discovering, developing, and maximizing the value of multiple large-scale upstream projects around the world. Our experience, industry relationships and technical expertise are our core competitive strengths and are crucial to our success.
The economic disruption resulting from Russia’s continued war in Ukraine, ongoing instability in the Middle East, a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions could further materially impact the Company’s business in future periods.
The economic disruption resulting from Russia’s continued war in Ukraine, ongoing instability in the Middle East and Latin America, a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions could further materially impact the Company’s business in future periods.
Santa Cruz MC 563 40.5 % Kosmos Production (7) Tornado GC 281 35.0 % Talos Production (7) Winterfell GC 943 / 944 25.0 % Beacon Production (7) Tiberius KC 964 50.0 % Kosmos Appraisal (7) Mauritania Greater Tortue Ahmeyim(1) Block C8 (3) 26.8 % BP Production/Development 2049(8) Senegal Greater Tortue Ahmeyim(1) Saint Louis Offshore Profond (3) 26.7 % BP Production/Development 2044(9) Teranga Cayar Offshore Profond 90.0 % (6) Kosmos Appraisal 2026 Yakaar Cayar Offshore Profond 90.0 % (6) Kosmos Appraisal 2026 Equatorial Guinea Ceiba Field and Okume Complex(1) Block G 40.4 % Trident Production 2040 ______________________________________ (1) For information concerning our estimated proved reserves as of December 31, 2024, see “—Our Reserves.” (2) The Jubilee Field straddles the boundary between the WCTP petroleum contract and the DT petroleum contract offshore Ghana.
Santa Cruz MC 563 40.5 % Kosmos Production (8) Tornado GC 281 35.0 % Talos Production (8) Winterfell GC 943 / 944 25.0 % Beacon Production (8) Tiberius KC 964 50.0 % Kosmos Appraisal (8) Mauritania Greater Tortue Ahmeyim(1) Block C8 (4) 26.8 % BP Production/Development 2049(9) Senegal Greater Tortue Ahmeyim(1) Saint Louis Offshore Profond (4) 26.7 % BP Production/Development 2044(10) Teranga Cayar Offshore Profond 90.0 % (7) Kosmos Appraisal 2026 Yakaar Cayar Offshore Profond 90.0 % (7) Kosmos Appraisal 2026 Equatorial Guinea Ceiba Field and Okume Complex(1) Block G 40.4 % Trident Production 2040 ______________________________________ (1) For information concerning our estimated proved reserves as of December 31, 2025, see “—Our Reserves.” (2) The Jubilee Field straddles the boundary between the WCTP petroleum contract and the DT petroleum contract offshore Ghana.
Greater Tortue Ahmeyim (GTA) Development The Greater Tortue Ahmeyim Field, discovered by the Tortue‑1 well in May 2015, in Mauritania Block C8 and by the Guembuel-1 well in January 2016, in the Senegal Saint-Louis Offshore Profond Block covers an area within both the C8 and Saint-Louis Offshore Profond Blocks.
Greater Tortue Ahmeyim (GTA) Development The Greater Tortue Ahmeyim Field, discovered by the Tortue‑1 well in May 2015 (in Mauritania Block C8) and by the Guembeul-1 well in January 2016 (in the Senegal Saint-Louis Offshore Profond Block) covers an area within both the C8 and Saint-Louis Offshore Profond Blocks.
Gross and Net Undeveloped and Developed Acreage The following table sets forth certain information regarding the developed and undeveloped portions of our license and lease areas as of December 31, 2024 for the countries in which we currently operate.
Gross and Net Undeveloped and Developed Acreage The following table sets forth certain information regarding the developed and undeveloped portions of our license and lease areas as of December 31, 2025 for the countries in which we currently operate.
(6) PETROSEN has the right to increase its participating interest after final investment decision and issuance of an exploitation authorization to up to 35%. The interest percentage does not give effect to the exercise of such option.
(7) PETROSEN has the right to increase its participating interest after final investment decision and issuance of an exploitation authorization to up to 35%. The interest percentage does not give effect to the exercise of such option.
RSC independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4‑10(a)(2) of Regulation S‑X.
RSC independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and 23 Table of Contents operating conditions, consistent with the definition in Rule 4‑10(a)(2) of Regulation S‑X.
The sales price for LNG under the Tortue Phase 1 SPA is set as a percentage of a crude oil price benchmark for the ACQ volumes (the “ACQ Sales Price”). The Tortue Phase 1 SPA has an initial term through the end of 2033, which can be extended by a further ten years at the co-venturers option.
The sales price for LNG under the Tortue Phase 1 SPA is set as a percentage of a crude oil price benchmark for the ACQ volumes (the “ACQ Sales Price”). The Tortue Phase 1 SPA has an initial term through the end of 2033, which can be extended by a further ten years at the sellers’ option.
Our business strategy is designed to accomplish this mission by focusing on three key objectives: (1) maximize the value of our producing assets; (2) progress our discovered resources toward project sanction and into proved reserves, production, and cash flow through efficient appraisal, development and exploitation; and (3) add new lower carbon resources through acquisitions and an efficient low cost exploration program in proven basins.
Our business strategy is designed to accomplish this mission by focusing on three key objectives: (1) maximize the value of our producing assets; (2) progress our discovered resources toward project sanction and into proved reserves, production, and cash flow through efficient appraisal, development and exploitation; and (3) add new lower cost resources through acquisitions and an efficient infrastructure-led exploration program in proven basins.
Changes at the Gulf of America include a positive revision of 3.5 MMBoe primarily driven by the Winterfell performance and an updated plan of development for Marmalard. There was also an extension of 1.2 MMboe in the Winterfell 21 Table of Contents field based on the results of the drilled Winterfell-3 well.
Changes at the Gulf of America include a positive revision of 3.5 MMBoe primarily driven by the Winterfell performance and an updated plan of development for Marmalard. There was also an extension of 1.2 MMboe in the Winterfell field based on the results of the drilled Winterfell-3 well.
In addition, our Reservoir Engineering team meets with representatives of our independent petroleum engineers to review our assets and discuss methods and assumptions used in preparation of the reserve and resource estimates. Finally, our senior management reviews reserve and resource estimates on an annual basis.
In addition, our Reservoir Engineering team meets with representatives of our independent petroleum engineers to review our assets and discuss 24 Table of Contents methods and assumptions used in preparation of the reserve and resource estimates. Finally, our senior management reviews reserve and resource estimates on an annual basis.
(3) The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal.
(4) The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal.
For Ghana, total proved natural gas reserves include fuel gas associated with the Jubilee and TEN Fields offshore Ghana of approximately 18.5 Bcf, 19.9 Bcf and 22.9 Bcf for 2024, 2023 and 2022, respectively. Our natural gas reserves in Equatorial Guinea are all associated with fuel gas.
For Ghana, total proved natural gas reserves include fuel gas associated with the Jubilee and TEN Fields offshore Ghana of approximately 19.9 Bcf, 18.5 Bcf and 19.9 Bcf for 2025, 2024 and 2023, respectively. Our natural gas reserves in Equatorial Guinea are all associated with fuel gas.
The well confirmed significant thickening of the gross reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters of net gas pay in two excellent quality reservoirs, including 46 meters in the Lower Cenomanian and 32 meters in the underlying Albian.
The well confirmed significant thickening of the gross 18 Table of Contents reservoir sequences down-dip. The Ahmeyim-2 well encountered 78 meters of net gas pay in two excellent quality reservoirs, including 46 meters in the Lower Cenomanian and 32 meters in the underlying Albian.
Also excluded from the table are 9 development wells awaiting completion. These wells are shown as “Wells Suspended or Waiting on Completion” in the table below.
Also excluded from the table are ten development wells awaiting completion. These wells are shown as “Wells Suspended or Waiting on Completion” in the table below.
Item 1. Business General Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America (formerly the U.S. Gulf of Mexico).
Item 1. Business General Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America.
We are also working with our partners and host governments on projects to reduce the carbon intensity of our production assets, such as the elimination of routine flaring in Ghana and Equatorial Guinea.
We are also working with our partners and host governments on projects to reduce the carbon intensity of our production assets, such as minimizing flaring in Ghana and Equatorial Guinea.
Trumbauer worked for DeGolyer and MacNaughton for 20 years prior to joining 24 Table of Contents Kosmos Energy, and we believe he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as understanding and applying SEC and other industry reserves definitions and guidelines.
Trumbauer worked for DeGolyer and MacNaughton for 20 years prior to joining Kosmos Energy, and we believe he is proficient in applying industry standard practices to engineering and geoscience evaluations as well as understanding and applying SEC and other industry reserves definitions and guidelines.
(7) Our Gulf of America blocks are held by production/operations, and the lease periods extend as long as production/governmental approved operations continue on the relevant block. (8) License expiration date can be extended by an additional ten years subject to certain conditions being met.
(8) Our Gulf of America blocks are held by production/operations, and the lease periods extend as long as production/governmental approved operations continue on the relevant block. 14 Table of Contents (9) License expiration date can be extended by an additional ten years subject to certain conditions being met.
RSC professionals subscribe to a code of professional conduct and RSC is a Registered Engineering Firm in the State of Texas. 23 Table of Contents For the years ended December 31, 2024, 2023 and 2022, we engaged RSC to prepare independent estimates of the extent and value of the proved reserves of certain of our oil and gas properties.
RSC professionals subscribe to a code of professional conduct and RSC is a Registered Engineering Firm in the State of Texas. For the years ended December 31, 2025, 2024 and 2023, we engaged RSC to prepare independent estimates of the extent and value of the proved reserves of certain of our oil and gas properties.
These acquisitions were targeted to increase and complement our existing properties, providing production diversification while increasing the quality of 10 Table of Contents investment opportunities in our portfolio.
These acquisitions were targeted to increase and complement our existing properties, providing production diversification while increasing the quality of investment opportunities in our portfolio.
We are focused on increasing production, cash flows and reserves from our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America as well as executing our appraisal and development efforts in the Gulf of America.
We are focused on increasing production, cash flows and reserves from our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America as well as executing our appraisal and development efforts in the Gulf of America and advancing additional phases of the GTA development in Mauritania and Senegal.
Kosmos Participating License Fields License Interest Operator Stage Expiration Ghana(1) Jubilee WCTP/DT (2) 38.6 % (2) Tullow Production 2034/2036 TEN DT 20.4 % (4) Tullow Production 2036 Gulf of America(1) Barataria MC 521 22.5 % Kosmos Production (7) Big Bend MC 697 / 698 / 742 5.3 % Talos Production (7) Gladden MC 800 20.0 % W&T Production (7) Kodiak MC 727 / 771 35.0 % Kosmos Production (7) Marmalard MC 255 / 300 11.4 % Murphy Production (7) Danny Noonan EC 381 / GB 506 30.0 % Talos Production (7) Odd Job MC 214 / 215 Various (5) Kosmos Production (7) SOB II MC 431 11.8 % Murphy Production (7) S.
Kosmos Participating License Fields License Interest Operator Stage Expiration Ghana(1) Jubilee WCTP/DT (2) 38.6 % (2)(3) Tullow Production 2040 (3) TEN DT 20.4 % (3)(5) Tullow Production 2040 (3) Gulf of America(1) Barataria MC 521 22.5 % Kosmos Production (8) Gladden MC 800 20.0 % W&T Production (8) Kodiak MC 727 / 771 35.0 % Kosmos Production (8) Marmalard MC 255 / 300 11.4 % Murphy Production (8) Danny Noonan EC 381 / GB 506 30.0 % Talos Production (8) Odd Job MC 214 / 215 Various (6) Kosmos Production (8) SOB II MC 431 11.8 % Murphy Production (8) S.
This strategic evolution was initially enabled by our acquisition of the Ceiba Field and Okume Complex assets offshore Equatorial Guinea in 2017, together with access to surrounding exploration licenses, and bolstered by the 2018 acquisition of Deep Gulf Energy, a deepwater company operating in the Gulf of America, which further enhanced our production, exploitation and infrastructure-led exploration capabilities.
This strategic evolution was initially enabled by our acquisition of the Ceiba Field and Okume Complex assets offshore Equatorial Guinea in 2017, and bolstered by the 2018 acquisition of Deep Gulf Energy, a deepwater company operating in the Gulf of America, which further enhanced our production, exploitation and infrastructure-led exploration capabilities.
Drilling activity The results of oil and natural gas wells drilled and completed for each of the last three years were as follows: Exploratory and Appraisal Wells(1) Development Wells(1) Productive(2) Dry(3) Total Productive(2) Dry(3) Total Total Total Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Year Ended December 31, 2024 Ghana — — — — — — 4 1.54 — — 4 1.54 4 1.54 Equatorial Guinea — — 1 0.43 1 0.43 2 0.81 — — 2 0.81 3 1.24 Gulf of America 1 0.25 — — 1 0.25 1 0.25 — — 1 0.25 2 0.50 Total 1 0.25 1.00 0.43 2 0.68 7 2.60 — — 7 2.60 9 3.28 Year Ended December 31, 2023 Ghana — — — — — — 7 2.70 — — 7 2.70 7 2.70 Gulf of America 1 0.25 — — 1 0.25 1 0.11 — — 1 0.11 2 0.36 Mauritania/Senegal — — — — — — 1 0.27 — — 1 0.27 1 0.27 Total 1 0.25 — — 1 0.25 9 3.08 — — 9 3.08 10 3.33 Year Ended December 31, 2022 Ghana(4)(5) — — 2 0.41 2 0.41 5 1.57 — — 5 1.57 7 1.98 Mauritania/Senegal — — — — — — 3 0.80 — — 3 0.80 3 0.80 Total — — 2 0.41 2 0.41 8 2.37 — — 8 2.37 10 2.78 ______________________________________ (1) As of December 31, 2024, 5 exploratory and appraisal wells have been excluded from the table until a determination is made if the wells have found proved reserves.
Drilling activity The results of oil and natural gas wells drilled and completed for each of the last three years were as follows: Exploratory and Appraisal Wells(1) Development Wells(1) Productive(2) Dry(3) Total Productive(2) Dry(3) Total Total Total Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Year Ended December 31, 2025 Ghana — — — — — — 1 0.39 — — 1 0.39 1 0.39 Gulf of America(4) — — 1 0.25 1 0.25 — — — — — — 1 0.25 Total — — 1.00 0.25 1 0.25 1 0.39 — — 1 0.39 2 0.64 Year Ended December 31, 2024 Ghana — — — — — — 4 1.54 — — 4 1.54 4 1.54 Equatorial Guinea — — 1 0.43 1 0.43 2 0.81 — — 2 0.81 3 1.24 Gulf of America 1 0.25 — — 1 0.25 1 0.25 — — 1 0.25 2 0.50 Total 1 0.25 1 0.43 2 0.68 7 2.60 — — 7 2.60 9 3.28 Year Ended December 31, 2023 Ghana — — — — — — 7 2.70 — — 7 2.70 7 2.70 Gulf of America 1 0.25 — — 1 0.25 1 0.11 — — 1 0.11 2 0.36 Mauritania|Senegal — — — — — — 1 0.27 — — 1 0.27 1 0.27 Total 1 0.25 — — 1 0.25 9 3.08 — — 9 3.08 10 3.33 ______________________________________ (1) As of December 31, 2025, two exploratory and appraisal wells have been excluded from the table until a determination is made if the wells have found proved reserves.
A gas pipeline from the Jubilee Field transports such natural gas onshore for processing and sale. In 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana through May 2024.
In Ghana, we currently produce associated gas from the Jubilee and TEN Fields. A gas pipeline from the Jubilee Field transports such natural gas onshore for processing and sale. In 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana through May 2024.
The December 31, 2024 reserve report was completed on January 15, 2025, and a copy is included as an exhibit to this report. In connection with the preparation of the December 31, 2024, 2023 and 2022 reserves report, RSC prepared its own estimates of our proved reserves.
The December 31, 2025 reserve report was completed on February 6, 2026, and a copy is included as an exhibit to this report. In connection with the preparation of the December 31, 2025, 2024 and 2023 reserves report, RSC prepared its own estimates of our proved reserves.
Excluding the impact of hedges, our realized oil price for 2024 was $78.70 per barrel. Title to Property We believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally accepted in the international oil and gas industry.
Excluding the impact of hedges, our realized oil price for 2025 was $66.89 per barrel. Title to Property We believe that we have satisfactory title to our oil and natural gas assets in accordance with standards generally accepted in the international oil and gas industry.
Management, including the CIO, and our information technology team, 30 Table of Contents regularly update the Audit Committee on the Company’s cybersecurity programs, material cybersecurity risks and mitigation strategies and provide cybersecurity reports quarterly that cover, among other topics, results of third-party testing and assessments of the Company’s cybersecurity programs, developments in cybersecurity and updates to the Company’s cybersecurity programs and mitigation strategies.
Management, including the Vice President of Administration, and our information technology team, regularly update the Audit Committee on the Company’s cybersecurity programs, material cybersecurity risks and mitigation strategies and provide cybersecurity reports quarterly that cover, among other topics, results of third-party testing and assessments of the Company’s cybersecurity programs, developments in cybersecurity and updates to the Company’s cybersecurity programs and mitigation strategies.
Actively Drilling or Wells Suspended or Completing Waiting on Completion Exploration Development Exploration Development Gross Net Gross Net Gross Net Gross Net Ghana Jubilee Unit — — — — — — 3 1.16 TEN — — — — — — 5 1.02 Equatorial Guinea Block G — — — — — — 1 0.40 Gulf of America Tiberius — — — — 1 0.50 — — Mauritania / Senegal Greater Tortue Ahmeyim — — — — 1 0.27 — — Senegal Cayar Profond — — — — 3 2.70 — — Total — — — — 5 3.47 9 2.58 ______________________________________ Domestic Supply Requirements Many of our petroleum contracts or, in some cases, the applicable law governing such agreements, grant a right to the respective host country to purchase certain amounts of oil/gas produced pursuant to such agreements at international market prices for domestic consumption.
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 — — 4 1.54 TEN — — — — — — 5 1.02 Equatorial Guinea Block G — — — — — — 1 0.40 Gulf of America Tiberius — — — — 1 0.50 — — Mauritania / Senegal Greater Tortue Ahmeyim — — — — 1 0.27 — — Total — — 1 0.39 2 0.77 10 2.96 ______________________________________ Domestic Supply Requirements Many of our petroleum contracts or, in some cases, the applicable law governing such agreements, grant a right to the respective host country to purchase certain amounts of oil/gas produced pursuant to such agreements at international market prices for domestic consumption.
Pursuing value accretive, opportunistic transactions that meet our strategic and financial objectives Since 2017, we have completed three separate significant acquisitions of oil and natural gas producing properties for total value of approximately $2.0 billion dollars, as of the effective date of the acquisitions.
Pursuing value accretive, opportunistic transactions that meet our strategic and financial objectives Since 2017, we have completed three separate significant acquisitions of oil and natural gas producing properties, with a total purchase price value of approximately $2.0 billion dollars, as of the effective date of each acquisition.
In December 2024, we received approval from the Ministry of Hydrocarbons and Mining Development for a twelve month extension to December 2025 for the second sub-period of the exploration phase of Block EG-24. Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 30% participating interest for all development and production operations.
Should a commercial discovery be made, GEPetrol’s 20% carried interest will convert to a 30% participating interest for all development and production operations. In December 2022, we received formal approval from the Ministry of Hydrocarbons and Mining Development to enter the second sub-period of the exploration phase of Block EG-24.
Developed Area Undeveloped Area Current Phase (Acres) (Acres) Total Area (Acres) Exploration Gross Net(1) Gross Net(1) Gross Net(1) Range (In thousands) Ghana(2) 164 43 33 9 197 52 — (2) Equatorial Guinea 65 26 1,184 799 1,249 825 2025 and 2026 Mauritania 129 35 — — 129 35 — Sao Tome and Principe — — 527 310 527 310 2025 Senegal 129 34 788 709 917 743 2026 Gulf of America(3) 104 28 121 61 225 89 through 2034 (3) Total 591 166 2,653 1,888 3,244 2,054 ______________________________________ (1) Net acreage based on Kosmos’ participating interests, including any options or back-in rights which have been exercised (Jubilee, TEN, and Greater Tortue Ahmeyim fields), but before the exercise of any options or back‑in rights that exist, but have not been exercised.
Developed Area Undeveloped Area Current Phase (Acres) (Acres) Total Area (Acres) Exploration Gross Net(1) Gross Net(1) Gross Net(1) Range (In thousands) Ghana(2) 164 43 33 9 197 52 — (2) Equatorial Guinea 65 26 1,184 799 1,249 825 2026 Mauritania 129 35 — — 129 35 — Sao Tome and Principe — — 527 310 527 310 2026 Senegal 129 34 788 709 917 743 2026 Gulf of America(3) 85 26 121 46 206 73 through 2034 (3) Total 572 164 2,653 1,873 3,225 2,038 ______________________________________ (1) Net acreage based on Kosmos’ participating interests, including any options or back-in rights which have been exercised (Jubilee, TEN, and Greater Tortue Ahmeyim fields), but before the exercise of any options or back‑in rights that exist, but have not been exercised.
The FLNG facility is protected behind a nearshore hub (which serves as a breakwater and LNG terminal) and is located on the Mauritania and Senegal maritime border. The FLNG facility for Phase 1 is designed to produce approximately 2.5 million tons per annum on average.
The FLNG facility is protected behind a nearshore hub (which serves as a breakwater and LNG terminal) and is located on the Mauritania and Senegal maritime border. The FLNG facility for Phase 1 is designed to produce at a nameplate capacity of approximately 2.7 million tons per annum.
For Mauritania/Senegal, total proved natural gas reserves include fuel gas of approximately 55.8 Bcf, 52.3 Bcf and 51.0 Bcf in 2024, 2023 and 2022, respectively. For the Gulf of America, total proved natural gas reserves include fuel gas of approximately 1.9 Bcf for 2024 and 1.1 Bcf for 2023.
For Mauritania|Senegal, total proved natural gas reserves include fuel gas of approximately 50.2 Bcf, 55.8 Bcf and 52.3 Bcf in 2025, 2024 and 2023, respectively. For the Gulf of America, total proved natural gas reserves include fuel gas of approximately 0.6 Bcf, 1.9 Bcf and 1.1 Bcf for 2025, 2024, and 2023, respectively.
Based on employee scores and feedback, Kosmos was named in the 2024 Top 100 Places to Work by the Dallas Morning News, as well as the Houston Chronicle. The feedback received through this annual survey is used to support continuous improvement and enhance the overall employee experience. In 2024, Kosmos had a retention rate of 94%.
Based on employee scores and feedback, Kosmos was named in the 2025 Top 100 Places to Work by the Dallas Morning News, as well as the Houston Chronicle. The feedback received through this annual survey is used to support continuous improvement and enhance the overall employee experience.
Over the past few years, our business strategy has evolved to focus on enhancing production through infill drilling and well work, infrastructure-led exploration, as well as value-accretive acquisitions.
Our business strategy has evolved to focus on enhancing production through infill drilling and well work, infrastructure-led exploration, as well as value-accretive acquisitions.
As of December 31, 2024, we had 243 employees with 199 being based in the United States and 44 residing in our foreign offices. Our workforce was approximately 37% gender diverse and approximately 21% minority. Employee Well-being Kosmos offers employees a robust range of benefits, including health plans, equity opportunities, savings plans, short- and long-term incentives.
As of December 31, 2025, we had 216 employees with 175 being based in the United States and 41 residing in our foreign offices. Our workforce was approximately 40% gender diverse and approximately 21% minority. Employee Well-being Kosmos offers employees a robust range of benefits, including health plans, equity opportunities, savings plans, short- and long-term incentives.
Moreover, public interest in the protection of the environment continues to increase. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted.
Moreover, public interest in the protection of the environment remains strong. Offshore drilling in some areas has been opposed by environmental groups and, in other areas, has been restricted.
Management is responsible for identifying and assessing material cybersecurity risks on an ongoing basis, establishing processes to ensure that such potential cybersecurity risk exposures are monitored, putting in place appropriate mitigation measures and maintaining cybersecurity programs.
Management is responsible for identifying and assessing material cybersecurity risks on an ongoing basis, establishing processes to ensure that such potential cybersecurity risk exposures are monitored, putting in place appropriate mitigation measures and maintaining cybersecurity programs. Our cybersecurity programs are under the direction of our Vice President of Administration.
The shared development of the Ceiba Field and Okume Complex consists of six subsea-well clusters that feed production to the Ceiba FPSO which is shared by both fields through a system of risers. The Okume Complex includes six platforms with an export line to move Okume production to the Ceiba FPSO.
The shared development of the Ceiba Field and Okume Complex consists of six subsea-well clusters that feed production to the Ceiba FPSO which is shared by both fields through a system of risers.
We maintain insurance coverage typical of the industry in the areas we operate in; these include property damage insurance, loss of production insurance, wreck removal insurance, control of well insurance, general liability including pollution liability to cover pollution from wells and other operations. We also participate in an insurance coverage program for the FPSOs we own.
We maintain insurance coverage typical of the industry in the areas we operate in; these include property damage insurance, loss of production insurance, wreck removal insurance, control of well insurance, and liability insurance including pollution liability to cover pollution from wells and other operations.
A corporate tax rate of 35% is applied to profits at a country level. The DT petroleum contract has a duration of 30 years from its effective date (July 2006).
A corporate tax rate of 35% is applied to profits at a country level. The DT petroleum contract has an original duration of 30 years from its effective date (July 2006), which has now been extended to 2040.
(4) Proved undeveloped reserves as of December 31, 2024 expected to be developed beyond five years since initial disclosure are all related to the Greater Tortue Ahmeyim Phase 1 project in Mauritania and Senegal which is a long-term project being developed under a continuous drilling program with long-term LNG sales obligations.
(4) Proved undeveloped reserves as of December 31, 2025 expected to be developed beyond five years since initial disclosure are all related to long-term projects which will be developed under a continuous drilling program primarily including the additional wells at Jubilee under the amended plan of development and the Greater Tortue Ahmeyim Phase 1 project in Mauritania and Senegal which is a long-term project being developed under a continuous drilling program with long-term LNG sales obligations.
The project is expected to help sustain long-term production from the Odd Job Field. Tornado The Tornado Field is producing from three Pliocene wells through the Helix Producer I, a ship-shaped, dynamically-positioned production platform in the deepwater Gulf of America, which is operated by Talos Energy.
To sustain long-term production from the field, we installed a subsea pump in the field in 2024. Tornado The Tornado Field is producing from three Pliocene wells through the Helix Producer I, a ship-shaped, dynamically-positioned production platform in the deepwater Gulf of America, which is operated by Talos Energy.
As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses and leases than our financial or personnel resources will permit.
Many of these competitors have financial and technical resources and staff that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses and leases than our financial or personnel resources will permit.
Kodiak The Kodiak Field is producing from two wells, which are completed in the Middle Miocene sands. These wells are flowing through the Devils Tower Spar platform, which is operated by ENI US Operating Co. Inc. (“ENI”). One of these wells, the Kodiak-3 infill well, was brought online in April 2021.
Kodiak The Kodiak Field is producing from two wells, which are completed in the Middle Miocene sands. These wells are flowing through the Devils Tower Spar platform, which is operated by ENI US Operating Co. Inc. (“ENI”).
In its relatively brief history, we have successfully opened two new hydrocarbon basins through the discovery of the Jubilee Field offshore Ghana in 2007 and the Greater Tortue Ahmeyim Field in 2015 (which includes the Ahmeyim and Guembeul discoveries offshore Mauritania and Senegal in 2015 and 2016, respectively).
We have a history of opening new hydrocarbon basins including the discovery of the Jubilee Field offshore Ghana in 2007 and the Greater Tortue Ahmeyim Field in 2015 (which includes the Ahmeyim and Guembeul discoveries offshore Mauritania and Senegal in 2015 and 2016, respectively).
Dated Brent crude, the benchmark for our international oil sales, ranged from approximately $71 to $93 per barrel during 2024. HLS crude, the benchmark for our Gulf of America oil sales, which generally trades at a discount to Dated Brent, ranged from approximately $66 to $90 during 2024.
Dated Brent crude, the benchmark for our international oil sales, ranged from approximately $60 to $83 per barrel during 2025. HLS crude, the benchmark for the majority of our Gulf of America oil sales, which generally trades at a discount to Dated Brent, ranged from approximately $57 to $83 during 2025.
We currently have crude oil marketing sales agreements with oil marketers to market our share of the Jubilee, TEN and Ceiba Field and Okume Complex oil, and we approve the terms of each sale proposed by such agents.
We currently have crude oil marketing sales agreements with oil marketers to market our share of the Jubilee, TEN and Ceiba Field and Okume Complex oil, and we approve the terms of each sale proposed by such agents. In the Gulf of America, Kosmos has historically sold crude oil on monthly contracts to various purchasers.
Over the years, we have entered into agreements with multiple oil marketing agents to market our share of the Jubilee and TEN Fields oil, and we approve the terms of each sale proposed by such agent.
Over the years, we have entered into agreements with multiple oil marketing agents to market our share of the Jubilee and TEN Fields oil, and we approve the terms of each sale proposed by such agent. Natural gas is sold monthly to the Government of Ghana through an interim gas sales agreement.
We also maintain insurance to partially protect against loss of production revenues from certain of our producing assets. 11 Table of Contents Operations by Geographic Area We currently have operations in Africa and the Gulf of America.
We also maintain insurance to partially protect against loss of production revenues from certain of our key producing assets. 12 Table of Contents Operations by Geographic Area We currently have operations in Africa and the Gulf of America. Presently, our operating revenues are generated from our operations offshore Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America.
We have demonstrated successful value-accretive acquisitions with the acquisition of additional interests in the Jubilee and TEN fields offshore Ghana in 2021 as well as the Kodiak and Winterfell fields in the Gulf of America in 2022.
Most recently, we have demonstrated infrastructure-led exploration success through the Winterfell and Tiberius discoveries in the Gulf of America in 2021 and 2023, respectively. We have demonstrated successful value-accretive acquisitions with the acquisition of additional interests in the Jubilee and TEN fields offshore Ghana in 2021 as well as the Kodiak field in the Gulf of America in 2022.
Following closing of the acquisition, Kosmos’ interest in the Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN Fields increased from 17.0% to 28.1%. In November 2021, we received notice from Tullow Oil plc (“Tullow”) that they were exercising their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP.
In November 2021, we received notice from Tullow Oil plc (“Tullow”) that they were exercising their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. Following completion of the acquisition and pre-emption process, Kosmos’ interest in the Jubilee Unit Area is 38.6% and Kosmos’ interest in the TEN Fields is 20.4%.
In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Hydrocarbons and Mining Development of Equatorial Guinea to extend the Block G petroleum contract term; harmonizing the expiration of the Ceiba Field and Okume Complex production licenses (from 2029 and 2034 respectively) to 2040. The license extensions support the next phase of investment in the licenses.
The Okume Complex includes six platforms with an export line to move Okume production to the Ceiba FPSO. 19 Table of Contents In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Hydrocarbons and Mining Development of Equatorial Guinea to extend the Block G petroleum contract term; harmonizing the expiration of the Ceiba Field and Okume Complex production licenses (from 2029 and 2034 respectively) to 2040.
(9) License expiration date can be extended by an additional twenty years subject to certain conditions being met. 13 Table of Contents Exploration License and Lease Areas Kosmos Average Number of Participating Current Phase Country Blocks Interest Operator(s) Expiration Range Equatorial Guinea 3 54.5% (1) Kosmos, Panoro 2025 and 2026 Sao Tome and Principe 1 58.9% (2) Kosmos 2025 Senegal 1 90.0% (3) Kosmos 2026 Gulf of America 41 38.2% Kosmos, Occidental, Beacon, LLOG, Murphy, Talos, W&T Offshore, Houston Energy through 2034 (4) ______________________________________ (1) Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.
Exploration License and Lease Areas Kosmos Average Number of Participating Current Phase Country Blocks Interest Operator(s) Expiration Range Equatorial Guinea 2 52.0% (1) Kosmos, Panoro 2026 Sao Tome and Principe 1 58.9% (2) Kosmos 2026 Senegal 1 90.0% (3) Kosmos 2026 Gulf of America 36 38.6% Kosmos, Occidental, Beacon, Harbour, Murphy, Talos, W&T Offshore, Shell through 2034 (4) ______________________________________ (1) Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.
(5) Natural gas liquids proved reserves represent an immaterial amount of our total proved reserves. Therefore, we have aggregated natural gas liquids and crude oil/condensate reserves information. Changes during the year ended December 31, 2024 at Jubilee resulted in an overall decrease of 16.1 MMBoe. Jubilee net production of 14.0 MMBoe was the largest contributing factor to the decrease.
(5) Natural gas liquids proved reserves represent an immaterial amount of our total proved reserves. Therefore, we have aggregated natural gas liquids and crude oil/condensate reserves information. Changes during the year ended December 31, 2025 at Jubilee resulted in an overall increase of 13.5 MMBoe.
The WCTP petroleum contract has a duration of 30 years from its effective date (July 2004). 14 Table of Contents Ghana Deepwater Tano Block Tullow is the operator of the Deepwater Tano Block.
The WCTP petroleum contract has an original duration of 30 years from its effective date (July 2004), which has now been extended to 2040. 15 Table of Contents Ghana Deepwater Tano Block Tullow is the operator of the Deepwater Tano Block.
The Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana through May 2024.
During 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana through May 2024. This interim gas sales agreement was subsequently extended to November 2025 at a price of approximately $3.00 per MMBtu.
In the Gulf of America, we sell crude oil to purchasers typically through monthly contracts, with the sale taking place at multiple points offshore, depending on the particular property. Natural gas is sold to purchasers monthly through long-term contracts, with the sale taking place either offshore or at an onshore gas processing plant after the removal of NGLs.
Natural gas is sold to purchasers monthly through long-term contracts, with the sale taking place either offshore or at an onshore gas processing plant after the removal of NGLs.
In December 2024, the partnership entered into a drilling rig contract for the next development drilling campaign in the Jubilee Field, which is expected to commence in the second quarter of 2025.
In December 2024, the partnership entered into a drilling rig contract for the next development drilling campaign in the Jubilee Field, which commenced in the second quarter of 2025. The partnership successfully brought one producer well online in July 2025.
The residue gas left over is sold to natural gas purchasers as natural gas sales (referenced above). The contracts for NGL sales are with the processing plant. The prices received for the NGLs are either tied to indices or are based on what the processing plant can receive from a third-party purchaser.
The contracts for NGL sales are with the processing plant. The prices received for the NGLs are either tied to indices or are based 27 Table of Contents on what the processing plant can receive from a third-party purchaser.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeFor a discussion of recent drilling and climate change executive orders signed by former President Biden and the potential impact of the new Trump Administration on these orders, see the risk factor earlier in this 10-K titled “ Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic and environmental circumstances, and changes in laws and regulations, in the countries and regions in which we operate .” In addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in the past few years, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, such as, for example, a proposal to significantly increase the minimum financial responsibility demonstration required under the Oil Pollution Act of 1990.
Biggest changeIn addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in recent years, there have been a variety of proposals and initiatives to change existing laws, regulations and agency practices that could affect offshore development and production, such as, for example, proposals to increase or otherwise revise the minimum financial responsibility or other security required under the Oil Pollution Act of 1990 or otherwise applicable to offshore lessees and operators.
These factors include, but are not limited to, market fluctuations of prices (such as recent significant variations in oil, natural gas and LNG prices), proximity, capacity and availability of drilling rigs and related equipment, qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability, access to markets and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil and natural gas, the ability to flare or vent natural gas, health and safety matters, environmental protection and climate change).
These factors include, but are not limited to, market fluctuations of prices (such as recent significant variations in oil, natural gas, and LNG prices), proximity, capacity and availability of drilling rigs and related equipment, qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability, access to markets and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil, natural gas, and LNG, the ability to flare or vent natural gas, health and safety matters, environmental protection and climate change).
There can be no assurance that future disagreements will not arise with any host government, national oil companies, and/or contractual counterparties that may have a material adverse effect on our exploration, development or production activities, our ability to operate, our rights under our licenses and local laws or our rights to monetize our interests, but if such disagreements do arise we intend to vigorously dispute them if necessary.
There can be no assurance that disagreements will not arise with any host government, national oil companies, and/or contractual counterparties that may have a material adverse effect on our exploration, development or production activities, our ability to operate, our rights under our licenses and local laws or our rights to monetize our interests, but if such disagreements do arise we intend to vigorously dispute them if necessary.
The market price for our common stock may be influenced by many factors, including, but not limited to: • the price of oil, natural gas and LNG; • the success of our exploration and development operations, and the marketing of any oil and natural gas we produce; • operational incidents; • regulatory developments in the United States and foreign countries where we operate; • the recruitment or departure of key personnel; • quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us; • market conditions in the industries in which we compete and issuance of new or changed securities; • analysts’ reports or recommendations; • the failure of securities analysts to cover our common stock or changes in financial estimates by analysts; • the inability to meet the financial estimates of analysts who follow our common stock; • the issuance or sale of any additional securities of ours; 57 Table of Contents • investor perception of our company and of the industry in which we compete; and • general economic, political and market conditions.
The market price for our common stock may be influenced by many factors, including, but not limited to: • the price of oil, natural gas and LNG; • the success of our exploration and development operations, and the marketing of any oil and natural gas we produce; • operational incidents; • regulatory developments in the United States and foreign countries where we operate; 56 Table of Contents • the recruitment or departure of key personnel; • quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us; • market conditions in the industries in which we compete and issuance of new or changed securities; • analysts’ reports or recommendations; • the failure of securities analysts to cover our common stock or changes in financial estimates by analysts; • the inability to meet the financial estimates of analysts who follow our common stock; • the issuance or sale of any additional securities of ours; • investor perception of our company and of the industry in which we compete; and • general economic, political and market conditions.
Our ability to use our federal net operating losses to offset potential future taxable income and related income taxes that would otherwise be due is dependent upon our generation of future taxable income and we cannot predict with certainty when, or whether, we will generate sufficient taxable income to use all of our net operating losses.
Our ability to use our federal and international net operating losses to offset potential future taxable income and related income taxes that would otherwise be due is dependent upon our generation of future taxable income and we cannot predict with certainty when, or whether, we will generate sufficient taxable income to use all of our net operating losses.
Our level of indebtedness could affect our operations in several ways, including the following: 48 Table of Contents • a significant portion or all of our cash flows, when generated, could be used to service our indebtedness; • a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions; • the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; • a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing; • our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; • additional hedging instruments may be required as a result of our indebtedness; • a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then‑outstanding bank borrowings; and • a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.
Our level of indebtedness could affect our operations in several ways, including the following: • a significant portion or all of our cash flows, when generated, could be used to service our indebtedness; • a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions; • the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; • a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing; • our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; • additional hedging instruments may be required as a result of our indebtedness; • a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then‑outstanding bank borrowings; and • a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.
Future activist efforts could result in the following: • delay or denial of drilling permits; • shortening of lease terms or reduction in lease size; • restrictions or delays on our ability to obtain additional seismic data; • restrictions on installation or operation of gathering or processing facilities; • restrictions on the use of certain operating practices; • legal challenges or lawsuits; • pressure or requirements for more analysis and disclosure of environmental and climate change-related risks and data, such as greenhouse gas emissions data; • damaging publicity about us; • increased regulation; 45 Table of Contents • increased costs of doing business; • reduced access to financing and hedging; • reduction in demand for our products; and • other adverse effects on our ability to develop our properties and/or undertake production operations.
Future activist efforts could result in the following: • delay or denial of drilling permits; • shortening of lease terms or reduction in lease size; • restrictions or delays on our ability to obtain additional seismic data; • restrictions on installation or operation of gathering or processing facilities; • restrictions on the use of certain operating practices; • legal challenges or lawsuits; • pressure or requirements for more analysis and disclosure of environmental and climate change-related risks and data, such as greenhouse gas emissions data; • damaging publicity about us; • increased regulation; • increased costs of doing business; • reduced access to financing and hedging; • reduction in demand for our products; and • other adverse effects on our ability to develop our properties and/or undertake production operations.
Business—Our Reserves” for information about our estimated oil and gas reserves and the present value of our net revenues at a 10% discount rate (“PV‑10”) and Standardized Measure of discounted future net revenues (as defined herein) as of December 31, 2024. In order to prepare our estimates, we must project production rates and the timing of development expenditures.
Business—Our Reserves” for information about our estimated oil and gas reserves and the present value of our net revenues at a 10% discount rate (“PV‑10”) and Standardized Measure of discounted future net revenues (as defined herein) as of December 31, 2025. In order to prepare our estimates, we must project production rates and the timing of development expenditures.
EPA announced its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and repot large methane emissions to the EPA.
EPA announced its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA.
These risks are discussed more fully below and include, but are not limited to, risks related to: Our Oil and Natural Gas Operations • We have limited proved reserves; • We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects; • Drilling wells is speculative and may not result in any discoveries; • Development wells may not result in commercially productive quantities of oil and gas reserves; • Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties; • We are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights; • Inability of third parties who contract with us to meet their obligations may adversely affect our financial results; • The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination; • We are not the operator on all of our license areas and facilities and do not hold all of the working interests in certain of our license areas; • Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate; • The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and gas reserves; • We may not be able to commercialize our interests in some of the natural gas produced from our license areas; • Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production; • We are subject to numerous risks inherent to the exploration, development, and production of oil and natural gas; • We are subject to drilling and other operational and environmental risks and hazards; • Our operations may be materially adversely affected by weather-related events, including, but not limited to, tropical storms and hurricanes, and the physical effects of climate change; • The development schedule of oil and natural gas projects is subject to delays and cost overruns; • Our offshore and deepwater operations involve special risks that could adversely affect our results of operations; • We had, and continue to have, disagreements with certain host governments and contractual counterparties regarding certain of our rights and responsibilities and may have future disagreements with our host governments and/or contractual counterparties; • The geographic locations of our licenses in Africa and the Gulf of America subject us to a risk of loss of revenue or curtailment of production from factors specifically affecting those areas; Our Business and Financial Condition • A substantial or extended decline in oil, natural gas and LNG prices may adversely affect our business, financial condition and results of operations; • Our business plan requires substantial additional capital; • We may be required to take write‑downs of the carrying values of our oil and natural gas assets due to decreases in the estimated future net cash flows from our operations, which may occur as a result of decreases in oil, natural gas, and 33 Table of Contents LNG prices, poor field performance, increased expenditures or changes in the timing or amount of investment, among other things, and such decreases could result in reduced availability under our commercial debt facility; • We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and ESG considerations including climate change and the transition to a lower carbon economy; • Outbreaks of disease may adversely affect our business operations and financial condition; • Deterioration in the credit or equity markets could adversely affect us; • We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage; • Slower global economic growth rates may materially adversely impact our operating results and financial position; • Increased costs and availability of capital could adversely affect our business; • Our derivative activities could result in financial losses or could reduce our income; • Our commercial debt facility and indentures governing our Senior Notes and Convertible Senior Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions; • Provisions of our Senior Notes and Convertible Senior Notes could discourage an acquisition of us by a third-party; • Our level of indebtedness may increase and thereby reduce our financial flexibility; • We are a holding company and our ability to make payments on our outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries; • We may be subject to risks in connection with acquisitions and the integration of acquisitions may be difficult; • If we fail to realize the anticipated benefits of acquisitions, our results of operations may be adversely affected; • A cybersecurity incident, including a breach of digital security, could result in information theft, data corruption, operational disruption, and/or financial loss; • Our ability to utilize net operating loss carryforwards may be subject to certain limitations; Regulation • Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic, and environmental circumstances; • More comprehensive and stringent regulation in the Gulf of America has materially increased costs and delays in offshore oil and natural gas exploration and production operations; • The oil and gas industry is intensely competitive and many of our competitors possess and employ substantially greater resources than us; • Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business; • We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs; • We may be exposed to assertions concerning or liabilities under anti‑corruption laws; • Federal regulatory law could have an adverse effect on our ability to use derivative instruments; General Matters • We are dependent on certain members of our management and technical team; • We operate in a litigious environment; • We face various risks associated with global activism; • Our share price may be volatile, and purchasers of our common stock could incur substantial losses; and • Holders of our common stock will be diluted if additional shares are issued. 34 Table of Contents Risks Relating to our Oil and Natural Gas Operations We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.
These risks are discussed more fully below and include, but are not limited to, risks related to: Our Oil and Natural Gas Operations • We have limited proved reserves; • We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects; • Drilling wells is speculative and may not result in any discoveries; • Development wells may not result in commercially productive quantities of oil and gas reserves; • Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties; • We are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights; • Inability of third parties who contract with us to meet their obligations may adversely affect our financial results; • The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination; • We are not the operator on all of our license areas and facilities and do not hold all of the working interests in certain of our license areas; • Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate; • The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and gas reserves; • We may not be able to commercialize our interests in some of the natural gas produced from our license areas; • Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production; • We are subject to numerous risks inherent to the exploration, development, and production of oil and natural gas; • We are subject to drilling and other operational and environmental risks and hazards; • Our operations may be materially adversely affected by weather-related events, including, but not limited to, tropical storms and hurricanes, and the physical effects of climate change; • The development schedule of oil and natural gas projects is subject to delays and cost overruns; • Our offshore and deepwater operations involve special risks that could adversely affect our results of operations; • We have had, and may in the future have, disagreements with certain host governments and contractual counterparties regarding certain of our rights and responsibilities; • The geographic locations of our licenses in Africa and the Gulf of America subject us to a risk of loss of revenue or curtailment of production from factors specifically affecting those areas; Our Business and Financial Condition • A substantial or extended decline in oil, natural gas and LNG prices may adversely affect our business, financial condition and results of operations; • Our business plan requires substantial additional capital; • We may be required to take write‑downs of the carrying values of our oil and natural gas assets due to decreases in the estimated future net cash flows from our operations, which may occur as a result of decreases in oil, natural gas, and LNG prices, poor field performance, increased expenditures or changes in the timing or amount of investment, among other things, and such decreases could result in reduced availability under our commercial debt facility; 33 Table of Contents • We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and ESG considerations including climate change and the transition to a lower carbon economy; • Outbreaks of disease may adversely affect our business operations and financial condition; • Deterioration in the credit or equity markets could adversely affect us; • We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage; • Slower global economic growth rates may materially adversely impact our operating results and financial position; • Increased costs and availability of capital could adversely affect our business; • Our derivative activities could result in financial losses or could reduce our income; • Our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions; • Provisions of our Senior Notes and Convertible Senior Notes could discourage an acquisition of us by a third-party; • Our level of indebtedness may increase and thereby reduce our financial flexibility; • We are a holding company and our ability to make payments on our outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries; • We may be subject to risks in connection with acquisitions and the integration of acquisitions may be difficult; • If we fail to realize the anticipated benefits of acquisitions, our results of operations may be adversely affected; • A cybersecurity incident, including a breach of digital security, could result in information theft, data corruption, operational disruption, and/or financial loss; • We are incorporating artificial intelligence technologies into our processes and these technologies may present business, operational, compliance, cybersecurity, and reputational risks; • Our ability to utilize net operating loss carryforwards may be subject to certain limitations; Regulation • Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic, and environmental circumstances; • More comprehensive and stringent regulation in the Gulf of America has materially increased costs and delays in offshore oil and natural gas exploration and production operations; • The oil and gas industry is intensely competitive and many of our competitors possess and employ substantially greater resources than us; • Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business; • We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs; • We may be exposed to assertions concerning or liabilities under anti‑corruption laws; • Federal regulatory law could have an adverse effect on our ability to use derivative instruments; General Matters • We are dependent on certain members of our management and technical team; • We operate in a litigious environment; • We face various risks associated with global activism; • Our share price may be volatile, and purchasers of our common stock could incur substantial losses; and • Holders of our common stock will be diluted if additional shares are issued. 34 Table of Contents Risks Relating to our Oil and Natural Gas Operations We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.
Furthermore, the marketability of expected oil and natural gas production from our discoveries and prospects will also be affected by numerous factors.
Furthermore, the marketability of expected oil, natural gas, and LNG production from our discoveries and prospects will also be affected by numerous factors.
The oil and natural gas business involves a variety of risks, including, but not limited to: • fires, blowouts, spills, cratering and explosions; • mechanical and equipment problems, including unforeseen engineering complications; • uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials; • gas flaring operations; • marine hazards with respect to offshore operations; • formations with abnormal pressures; • pollution, environmental risks, and geological problems; and • weather conditions and natural or man‑made disasters.
The oil and natural gas business involves a variety of risks, including, but not limited to: • fires, blowouts, spills, cratering and explosions; • mechanical and equipment problems, including unforeseen engineering complications; 40 Table of Contents • uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials; • gas flaring operations; • marine hazards with respect to offshore operations; • formations with abnormal pressures; • pollution, environmental risks, and geological problems; and • weather conditions and natural or man‑made disasters.
In the competitive market for our license areas, failure to drill these wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects or undeveloped discoveries.” 44 Table of Contents All of our proved reserves, oil and natural gas production and cash flows from operations are currently associated with our licenses offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America.
In the competitive market for our license areas, failure to drill these wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects or undeveloped discoveries.” All of our proved reserves, oil and natural gas production and cash flows from operations are currently associated with our licenses offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America.
For example, Russia’s continued war in Ukraine, ongoing instability in the Middle East, a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions and the effects on demand for oil and natural gas has resulted in significant variations in oil, natural gas and LNG prices.
For example, Russia’s continued war in Ukraine, ongoing instability in the Middle East and Latin America, a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions and the effects on demand for oil and natural gas has resulted in significant variations in oil, natural gas and LNG prices.
Some or all of these licenses could be affected should any region experience any of the following factors (among others): • severe weather, natural or man‑made disasters or acts of God; 42 Table of Contents • delays or decreases in production, the availability of equipment, facilities, personnel or services; • delays or decreases in the availability of capacity to transport, gather or process production; • military conflicts, civil unrest or political strife; and/or • international border disputes.
Some or all of these licenses could be affected should any region experience any of the following factors (among others): • severe weather, natural or man‑made disasters or acts of God; • delays or decreases in production, the availability of equipment, facilities, personnel or services; • delays or decreases in the availability of capacity to transport, gather or process production; • military conflicts, civil unrest or political strife; and/or • international border disputes.
These factors include, but are not limited to, the following: • changes in supply and demand for oil, natural gas, and LNG; • the actions of the Organization of the Petroleum Exporting Countries; • speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts; • global economic conditions; • political and economic conditions, including embargoes in oil‑producing countries or affecting other oil‑producing activities, particularly in the Middle East, Africa, Russia and Central and South America; • the continued threat of terrorism and the impact of military and other action, including U.S. military operations outside the United States; • the level of global oil and natural gas exploration and production activity; • the level of global oil inventories and oil refining capacities; • weather conditions and natural or man‑made disasters; • technological advances affecting energy consumption; • governmental regulations and taxation policies; • proximity and capacity of transportation facilities; • the development and exploitation of alternative fuels or energy sources; • the price and availability of competitors’ supplies of oil and natural gas; and 43 Table of Contents • the price, availability or mandated use of alternative fuels or energy sources.
These factors include, but are not limited to, the following: 42 Table of Contents • changes in supply and demand for oil, natural gas, and LNG; • the actions of the Organization of the Petroleum Exporting Countries; • speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts; • global economic conditions; • political and economic conditions, including embargoes in oil‑producing countries or affecting other oil‑producing activities, particularly in the Middle East, Africa, Russia and Central and South America; • the continued threat of terrorism and the impact of military and other action, including U.S. military operations outside the United States in oil producing nations such as Venezuela and Iran; • the level of global oil and natural gas exploration and production activity; • the level of global oil inventories and oil refining capacities; • weather conditions and natural or man‑made disasters; • technological advances affecting energy consumption; • governmental regulations and taxation policies; • proximity and capacity of transportation facilities; • the development and exploitation of alternative fuels or energy sources; • the price and availability of competitors’ supplies of oil and natural gas; and • the price, availability or mandated use of alternative fuels or energy sources.
As dependence on digital technologies has increased, cybersecurity incidents, including deliberate attacks or unintentional events, have also increased. A cyber‑attack could include gaining unauthorized access to digital systems for 50 Table of Contents purposes of misappropriating assets or personal, confidential or proprietary information, corrupting data, or causing operational disruption, or result in denial‑of‑service on websites.
As dependence on digital technologies has increased, cybersecurity incidents, including deliberate attacks or unintentional events, have also increased. A cyber‑attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or personal, confidential or proprietary information, corrupting data, or causing operational disruption, or result in denial‑of‑service on websites.
In addition, the U.S. government may seek to hold us liable for 55 Table of Contents successor liability for FCPA violations committed by companies in which we invest in (for example, by way of acquiring equity interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions with) or that we acquire.
In addition, the U.S. government may seek to hold us liable for successor liability for FCPA violations committed by companies in which we invest (for example, by way of acquiring equity interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions with) or that we acquire.
These regulatory initiatives effectively slowed down the pace of drilling and production operations in the Gulf of America as adjustments were being made in operating procedures, certification requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present-day bureaus.
These regulatory initiatives have, at various times, effectively slowed down the pace of drilling and production operations in the Gulf of America as adjustments were being made in operating procedures, certification requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present-day bureaus.
Our operations may also be adversely affected by laws and policies of the jurisdictions, including the jurisdictions where our oil and gas operating activities are located as well as the United Kingdom and the Cayman Islands and other 52 Table of Contents jurisdictions in which we do business, that affect foreign trade and taxation.
Our operations may also be adversely affected by laws and policies of the jurisdictions, including the jurisdictions where our oil and gas operating activities are located as well as the United Kingdom and the Cayman Islands and other jurisdictions in which we do business, that affect foreign trade and taxation.
The successful acquisition of these assets or businesses requires an assessment of several factors, including: • recoverable reserves; • future oil, natural gas and LNG prices and their appropriate differentials; 49 Table of Contents • development and operating costs; and • potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain.
The successful acquisition of these assets or businesses requires an assessment of several factors, including: • recoverable reserves; • future oil, natural gas and LNG prices and their appropriate differentials; • development and operating costs; and • potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain.
Our ability to market our oil and natural gas production will depend substantially on the availability and capacity of processing facilities, oil and LNG tankers and other infrastructure, including FPSOs, owned and operated by third parties. Our failure to obtain such facilities on acceptable terms could materially harm our business.
Our ability to market our oil and natural gas production depends substantially on the availability and capacity of processing facilities, oil and LNG tankers and other infrastructure, including FPSOs, owned and operated by third parties. Our failure to obtain such facilities on acceptable terms could materially harm our business.
On May 15, 2019, BSEE published a final rule with an effective date of July 15, 2019 that revises requirements for well design, well control, casing, cementing, real-time monitoring (RTM), and subsea containment. These revisions modify regulations pertaining to offshore oil and gas drilling, completions, workovers, and decommissioning in accordance with Executive and Secretary of the Interior's Orders.
On May 15, 2019, BSEE published a final rule with an effective date of July 15, 2019 that revised requirements for well design, well control, casing, cementing, real-time monitoring (RTM), and subsea containment. These revisions modified regulations pertaining to offshore oil and gas drilling, completions, workovers, and decommissioning in accordance with Executive and Secretary of the Interior's Orders.
If any of these officers or other key personnel retires, resigns or becomes unable to continue in their present roles and is not adequately replaced, our results of operations and financial 56 Table of Contents condition could be materially adversely affected.
If any of these officers or other key personnel retires, resigns or becomes unable to continue in their present roles and is not adequately replaced, our results of operations and financial condition could be materially adversely affected.
Discoveries may become uneconomic as a result of an increase in operating costs to produce oil and natural gas, among other factors. Our actual operating costs and rates of production may differ materially from 40 Table of Contents our current estimates.
Discoveries may become uneconomic as a result of an increase in operating costs to produce oil and natural gas, among other factors. Our actual operating costs and rates of production may differ materially from our current estimates.
To the extent the existing regulatory initiatives implemented and pursued over the past few years or any future restrictions, whether through legislative or regulatory means or increased or broadened permitting and enforcement programs, foster uncertainties or delays in our offshore oil and natural gas development or exploration activities, then such conditions may have a material adverse effect on our business, financial condition and results of operations.
To the extent the existing regulatory initiatives implemented and pursued in recent years or any future restrictions, whether through legislative or regulatory means or increased or broadened permitting and enforcement programs, foster uncertainties, delays or increased costs in our offshore oil and natural gas development or exploration activities, then such conditions may have a material adverse effect on our business, financial condition and results of operations.
Our future capital requirements will depend on many factors, including: • the scope, rate of progress and cost of our exploration, appraisal, development and production activities; • the success of our exploration, appraisal, development and production activities; • oil, natural gas, and LNG prices; • our ability to locate and acquire hydrocarbon reserves; • our ability to produce oil or natural gas from those reserves; • the terms and timing of any drilling and other production‑related arrangements that we may enter into; • the cost and timing of governmental approvals and/or concessions; • the effects of competition by other companies operating in the oil and gas industry; and • potential changes in investor and public preferences and sentiment towards ESG considerations including climate change and the transition to a lower carbon economy.
Our future capital requirements will depend on many factors, including: • the scope, rate of progress and cost of our exploration, appraisal, development and production activities; • the success of our exploration, appraisal, development and production activities; • oil, natural gas, and LNG prices; • our ability to locate and acquire hydrocarbon reserves; 43 Table of Contents • our ability to produce oil or natural gas from those reserves; • the terms and timing of any drilling and other production‑related arrangements that we may enter into; • the cost and timing of governmental approvals and/or concessions; • inflationary pressures leading to increasing costs; • the effects of competition by other companies operating in the oil and gas industry; and • potential changes in investor and public preferences and sentiment towards ESG considerations including climate change and the transition to a lower carbon economy.
Our commercial debt facility and the indentures governing our Senior Notes and Convertible Senior Notes include certain covenants that, among other things, restrict: • our investments, loans and advances and certain of our subsidiaries’ payment of dividends and other restricted payments; • our incurrence of additional indebtedness; • the granting of liens, other than liens created pursuant to the commercial debt facility or the indentures governing our Senior Notes and Convertible Senior Notes and certain permitted liens; • mergers, consolidations and sales of all or a substantial part of our business or licenses; • the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities; • the sale of assets (other than production sold in the ordinary course of business); and • in the case of the commercial debt facility, our capital expenditures that we can fund with the proceeds of our commercial debt facility.
Our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes include certain covenants that, among other things, restrict: • our investments, loans and advances and certain of our subsidiaries’ payment of dividends and other restricted payments; • our incurrence of additional indebtedness; • the granting of liens, other than liens created pursuant to the commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds or the indentures governing our Senior Notes and Convertible Senior Notes and certain permitted liens; • mergers, consolidations and sales of all or a substantial part of our business or licenses; • the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities; • the sale of assets (other than production sold in the ordinary course of business); and • in the case of the commercial debt facility and the GoA Term Loan Facility, our capital expenditures that we can fund with the proceeds of our commercial debt facility and GoA Term Loan Facility.
In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), contains rules that impose an annual limitation on the ability of a company with federal net operating loss carryforwards that undergoes an ownership change, which is generally any change in ownership of more than 50% of its stock (by value) over a three-year period, to utilize its federal net operating loss carryforwards in years after the ownership change.
In addition, with regard to our U.S. net operating losses only, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), contains rules that impose an annual limitation on the ability of a company with federal net operating loss carryforwards that undergoes an ownership change, which is generally any change in ownership of more than 50% of its stock (by value) over a three-year period, to utilize its federal net operating loss carryforwards in years after the ownership change.
Our costs of complying with current and future climate change, health, safety and environmental laws, the actions or omissions of our block partners and third-party contractors and our liabilities arising from releases of, or exposure to, regulated substances may adversely affect our results of operations and financial condition. See “Item 1. Business—Environmental Matters” for more information.
Our costs of complying with current and future climate change, health, safety and environmental laws, the actions or omissions of our block partners and third-party contractors and our liabilities arising from releases of, or exposure to, regulated substances may adversely affect our results of operations and financial condition. See “Item 1.
We are required to obtain environmental permits from governmental authorities for our operations, including drilling permits for our wells. We maintain policies and processes to comply with these various permits and laws and regulations to which we are subject.
We are required to obtain environmental permits from 53 Table of Contents governmental authorities for our operations, including drilling permits for our wells. We maintain policies and processes to comply with these various permits and laws and regulations to which we are subject.
We are subject to the U.S. Foreign Corrupt Practices Act (“FCPA”) and other laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or otherwise securing an improper business advantage.
Foreign Corrupt Practices Act (“FCPA”) and other laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or otherwise securing an improper business advantage.
The breach of any of these covenants could result in a default under our commercial debt facility and the indentures governing our Senior Notes and Convertible Senior Notes, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under such debt instruments, together with accrued interest, to be due and payable.
The breach of any of these covenants could result in a default under our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under such debt instruments, together with accrued interest, 47 Table of Contents to be due and payable.
Under certain petroleum contracts, we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the licenses. As of December 31, 2024, we have unfulfilled drilling obligations for one development well in Equatorial Guinea.
Under certain petroleum contracts, we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the licenses. As of December 31, 2025, we have a commitment to one development well in Equatorial Guinea.
Our ability to comply with these and other provisions of our commercial debt facility and the indentures governing our Senior Notes and Convertible Senior Notes may be impacted by changes in economic or business conditions, our results of operations or events beyond our control.
Our ability to comply with these and other provisions of our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes may be impacted by changes in economic or business conditions, our results of operations or events beyond our control.
Any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements regarding financial assurances, moratoria on new leases or otherwise adversely affecting our offshore activities could result in increased costs, limit our operations and adversely impact our future financial results.
Any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements regarding financial assurances, restrict or delay leasing or permitting or that otherwise adversely affect our offshore activities could result in increased costs, limit our operations and adversely impact our future financial results.
A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. President Trump has indicated that he intends to withdraw the United States from the Paris Agreement, as he did during his first term. Separately, in December 2023, the U.S.
A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. In January 2026, President Trump once again withdrew the United States from the Paris Agreement, as he did during his first term. Separately, in December 2023, the U.S.
The respective interests in the Jubilee Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the Jubilee UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit.
The respective interests in the Jubilee Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the Jubilee UUOA, the percentage of such contributed interests is subject to a process of redetermination.
Our offshore and deepwater operations involve special risks that could adversely affect our results of operations. 41 Table of Contents Offshore operations are subject to a variety of special operating risks specific to the marine environment, such as capsizing, sinking, collisions and damage or loss to pipeline, subsea or other facilities or from weather conditions.
Offshore operations are subject to a variety of special operating risks specific to the marine environment, such as capsizing, sinking, collisions and damage or loss to pipeline, subsea or other facilities or from weather conditions.
These types of derivative arrangements may limit the benefit we could receive from increases in the prices for oil, natural gas and LNG or beneficial interest rate fluctuations and may expose us to cash margin requirements.
These types of derivative arrangements may limit the benefit we could receive from increases in the prices for oil, natural gas and LNG or beneficial interest rate fluctuations and may expose us to cash margin requirements. In addition, a reduction in our ability to access credit could reduce our ability to implement derivative arrangements on commercially reasonable terms.
Disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital.
The loss or departure of one or more members of our management and technical team could be detrimental to our future success. Additionally, a significant amount of shares in Kosmos held by members of our management and technical team has vested. There can be no assurance that our management and technical team will remain in place.
Additionally, a significant amount of shares in Kosmos held by members of our management and technical team has vested. There can be no assurance that our management and technical team will remain in place.
In addition, the shutting in of wells can lead to mechanical problems upon bringing the production back online, potentially resulting in decreased production and increased remediation costs.
In addition, the shutting in of wells can lead to mechanical problems upon bringing the production back online, potentially resulting in decreased production and increased remediation costs. We are subject to numerous risks inherent to the exploration and production of oil and natural gas.
At December 31, 2024, we had $900.0 million outstanding and $450.0 million of committed undrawn available capacity under our commercial debt facility. As of December 31, 2024, we had $1.9 billion principal amount of Senior Notes and Convertible Senior Notes outstanding.
At December 31, 2025, we had $1,200.0 million outstanding and $150.0 million of committed undrawn available capacity under our commercial debt facility. As of December 31, 2025, we had $1.8 billion principal amount of Senior Notes and Convertible Senior Notes outstanding and $150 million outstanding under the GoA Term Loan Facility.
For example, compliance with West African Monetary Union Regulations in Senegal could result in our exposure to, among other things, foreign exchange risks/costs and impact the efficiency of moving cash balances in and out of country. In addition, we are subject to uncertainties surrounding the economies and fiscal health of the countries in which we operate.
For example, compliance with West African Monetary Union Regulations in Senegal could 51 Table of Contents result in our exposure to, among other things, foreign exchange risks/costs and impact the efficiency of moving cash balances in and out of country.
If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. If we fail to realize the anticipated benefits of acquisitions, our results of operations may be adversely affected.
If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new 44 Table of Contents financing, we may have to sell significant assets.
We also rely on continuing access to drilling rigs and construction vessels suitable for the environment in which we operate. The delivery of drilling rigs or construction vessels may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs or vessels in the future.
The delivery of drilling rigs or construction vessels may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs, vessels or other operating infrastructure in the future.
Following the completion of the pre-emption by Tullow in March of 2022, Kosmos’ interest in the Jubilee Unit Area decreased from 42.1% to 38.6%. An additional redetermination could occur sometime if requested by a party that holds greater than a 10% interest in the Jubilee Unit.
Following the acquisition of Anadarko WCTP Company in October 2021 and completion of the subsequent pre-emption by Tullow in March of 2022, Kosmos’ interest in the Jubilee Unit Area now stands at 38.6%. An additional redetermination could occur sometime if requested by a party that holds greater than a 10% interest in the Jubilee Unit.
The success of an acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours.
If we fail to realize the anticipated benefits of acquisitions, our results of operations may be adversely affected. 49 Table of Contents The success of an acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours.
Our inability to export associated natural gas from the Jubilee Field could eventually impact our oil production and could cause us to re-inject or flare any natural gas we cannot export. 39 Table of Contents In Mauritania and Senegal, we plan to export the majority of our gas resource to the LNG market.
Our inability to export associated natural gas from the Jubilee Field could eventually impact our oil production and could cause us to re-inject or flare any natural gas we cannot export. In Mauritania and Senegal, while we currently only export our gas resource to the LNG market, we also intend to utilize existing facilities for domestic gas delivery.
We may be exposed to assertions concerning or liabilities under the U.S. Foreign Corrupt Practices Act and other anti‑corruption laws, and any such assertions or determination that we violated the U.S. Foreign Corrupt Practices Act or other such laws could result in significant costs to Kosmos and have a material adverse effect on our business.
Foreign Corrupt Practices Act or other such laws could result in significant costs to Kosmos and have a material adverse effect on our business. We are subject to the U.S.
Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available in a timely and cost‑effective fashion.
Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available in a timely and cost‑effective fashion. Our offshore and deepwater operations involve special risks that could adversely affect our results of operations.
Moreover, to the extent that purchasers of our future production, if any, rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to us if such purchasers were unable to access the credit or equity markets for an extended period of time. 46 Table of Contents We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage.
Moreover, to the extent that purchasers of our future production, if any, rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to us if such purchasers were unable to access the credit or equity markets for an extended period of time.
Relatedly, in November 2024, the U.S. EPA finalized a rule implementing the Waste Emissions Charge, a fee for large emitters of methane if their emissions exceed certain levels, as required by the Inflation Reduction Act.
Relatedly, in November 2024, the U.S. EPA finalized a rule implementing the Waste Emissions Charge, a fee for large emitters of methane if their emissions exceed certain levels, as required by the Inflation Reduction Act. In addition, numerous other climate change and GHG emissions laws, regulations or rules have been proposed or are in various stages of review and/or challenge.
If travel bans are implemented or extended to the countries in which we operate, or contractors or personnel refuse to travel there, we could be adversely affected. If services are obtained, costs associated with those services could be significantly higher than planned which could have a material adverse effect on our business, results of operations, and future cash flow.
If services are obtained, costs associated with those services could be significantly higher than planned which could have a material adverse effect on our business, results of operations, and future cash flow. In addition, should an Ebola or other virus outbreak spread to the countries in which we operate, access to the FPSOs could be restricted and/or terminated.
We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration development, and production activities and ESG considerations, including climate change and the transition to a lower carbon economy. Opposition toward oil and gas drilling, development, and production activity has been growing globally.
Any such sale could have a material adverse effect on our business and financial results. We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration development, and production activities and ESG considerations, including climate change and the transition to a lower carbon economy.
In addition, a reduction in our ability to access credit could reduce our ability to implement derivative arrangements on commercially reasonable terms. 47 Table of Contents Our commercial debt facility and the indentures governing our Senior Notes and Convertible Senior Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.
Our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.
As a result, a well control incident could result in substantial liabilities, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price.
As a result, a well control incident could result in substantial liabilities, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price. We have had, and may in the future have, disagreements with certain host governments and contractual counterparties regarding certain of our rights and responsibilities.
Companies in the oil and gas industry are often the target of activist efforts from both individuals and non‑governmental organizations and other stakeholders regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Certain of these activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development.
Opposition toward oil and gas drilling, development, and production activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non‑governmental organizations and other stakeholders regarding safety, human rights, climate change, environmental matters, sustainability, and business practices.
Significant outbreaks of contagious diseases, and other adverse public health developments, could have a material impact on our business operations and financial condition. Many of our operations are currently, and will likely remain in the near future, in developing countries which are susceptible to outbreaks of disease and may lack the resources to effectively contain such an outbreak quickly.
Many of our operations are currently, and will likely remain in the near future, in developing countries which are susceptible to outbreaks of disease, such as the Ebola virus disease, and may lack the resources to effectively contain such an outbreak quickly.
To the extent we transact with counterparties in foreign jurisdictions, we or our transactions may become subject to such regulations. The impact of such regulations could be similar to those described above with respect to U.S. rules. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
The impact of such regulations could be similar to those described above with respect to U.S. rules. 55 Table of Contents Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows. General Risk Factors We are dependent on certain members of our management and technical team.
General Risk Factors We are dependent on certain members of our management and technical team. Our performance and success largely depend on the ability, expertise, judgment and discretion of our management and the ability of our technical team to identify, discover, evaluate, develop, and produce reserves.
Our performance and success largely depend on the ability, expertise, judgment and discretion of our management and the ability of our technical team to identify, discover, evaluate, develop, and produce reserves. The loss or departure of one or more members of our management and technical team could be detrimental to our future success.
As a result of these and other factors, we may not be able to compete successfully in an intensely competitive industry, which could cause a material adverse effect on our results of operations and financial condition. 53 Table of Contents Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business.
As a result of these and other factors, we may not be able to compete successfully in an intensely competitive industry, which could cause a material adverse effect on our results of operations and financial condition.
In addition, during 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas to the Government of Ghana through May 2024. This interim gas sales agreement was subsequently extended to November 2025 while the partners continue on-going discussions with the Government of Ghana regarding a long-term future gas sales agreement.
During 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas to the Government of Ghana through May 2024. This interim gas sales agreement was subsequently extended to November 2025 at a price of approximately $3.00 per MMBtu.
Consequently, our Unit Interest (participating interest in the Jubilee Unit) was increased from 37 Table of Contents 23.5% to 24.1% upon completion of the initial redetermination process. Following the acquisition of Anadarko WCTP Company, which owned a participating interest in the WCTP Block and DT Block, our Unit Interest (participating interest in the Jubilee Unit) increased from 24.1% to 42.1%.
Following an initial redetermination process completed on October 14, 2011, the tract participation was determined to be 54.4% 37 Table of Contents for the WCTP Block and 45.6% for the DT Block. Consequently, our Unit Interest (participating interest in the Jubilee Unit) was increased from 23.5% to 24.1% upon completion of the initial redetermination process.
We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented.
Such insurance, however, may contain exclusions and limitations on coverage or may not be available at a reasonable cost or at all. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented.
We are a holding company and our ability to make payments on our outstanding indebtedness, including our Senior Notes and Convertible Senior Notes, is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise.
Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital. 48 Table of Contents We are a holding company and our ability to make payments on our outstanding indebtedness, including our Senior Notes and Convertible Senior Notes, is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise.
We are subject to numerous risks inherent to the exploration and production of oil and natural gas. Oil and natural gas exploration and production activities involve many risks that a combination of experience, knowledge and interpretation may not be able to overcome.
Oil and natural gas exploration and production activities involve many risks that a combination of experience, knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and production activities and on the development of infrastructure that will allow us to take advantage of our discoveries.
For example, we have previously experienced mechanical issues at certain of our offshore production facilities, such as the turret bearing issue on the Jubilee FPSO. The equipment downtime caused by these mechanical issues negatively impacted oil production. Furthermore, deepwater operations generally, and operations in Africa, in particular, lack the physical and oilfield service infrastructure present in other regions.
The equipment downtime caused by these mechanical issues negatively impacted oil production. 41 Table of Contents Furthermore, deepwater operations generally, and operations in Africa, in particular, lack the physical and oilfield service infrastructure present in other regions.
Our commercial debt facility requires us to maintain certain financial ratios, such as debt service coverage ratios and cash flow coverage ratios. All of these restrictive covenants may limit our ability to move funds among our subsidiaries, operate our business, or expand or pursue our business strategies.
All of these restrictive covenants may limit our ability to move funds among our subsidiaries, operate our business, or expand or pursue our business strategies.
Accordingly, we could be held liable for all costs and liabilities arising out of their acts or omissions, which could have a material adverse effect on our results of operations and financial condition. 54 Table of Contents We are not fully insured against all risks and our insurance may not cover any or all health, safety or environmental claims that might arise from our operations or at any of our license areas.
Accordingly, we could be held liable for all costs and liabilities arising out of their acts or omissions, which could have a material adverse effect on our results of operations and financial condition.
If we were unable to repay such borrowings or interest, our lenders, successors or assignees could proceed against their collateral. If the indebtedness under our commercial debt facility and the indentures governing our Senior Notes and Convertible Senior Notes were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.
If the indebtedness under our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.
Because we maintain a diversified portfolio of assets overseas, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions.
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 Because we maintain a diversified portfolio of assets overseas, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions.
As cybersecurity threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Our ability to utilize net operating loss carryforwards may be subject to certain limitations.
As cybersecurity threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. We are incorporating artificial intelligence technologies into our processes and these technologies may present business, operational, compliance, cybersecurity, and reputational risks.
Exploration and production activities in the oil and gas industry are subject to local laws and regulations.
Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business. Exploration and production activities in the oil and gas industry are subject to local laws and regulations.
In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies. For example, an epidemic of the Ebola virus disease occurred in parts of West Africa in 2014 and continued through 2015.
In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies. 45 Table of Contents Our operations require contractors and personnel to travel to and from Africa as well as the unhindered transportation of equipment and oil and gas production (in the case of our producing fields).
We intend to maintain insurance against certain risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable. Such insurance, however, may contain exclusions and limitations on coverage or may not be available at a reasonable cost or at all.
We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage. We intend to maintain insurance against certain risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable.
Any such changes may have a material adverse effect on our business. We also cannot assure you that government approval will not be needed for direct or indirect transfers of our petroleum agreements or interests thereunder based on existing legislation. We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs.
Any resulting liabilities, penalties, suspensions or terminations could have a material adverse effect on our financial condition and results of operations. We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs.
However, that plan is contingent on making additional final investment decisions on our gas discoveries and constructing the necessary infrastructure to produce, liquefy and transport the gas to the market. Additionally, such plans are contingent upon receipt of required partner and government approvals.
This plan is contingent signing gas sales agreements for domestic gas and 39 Table of Contents the necessary infrastructure to transport the gas to domestic onshore markets being constructed. Additionally, such plans are contingent upon receipt of required partner and government approvals.

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Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeWhile we cannot predict the occurrence or outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows; however, an unfavorable outcome could have a material adverse effect on our results of operations for a specific interim period or year.
Biggest changeWhile we cannot predict the occurrence or outcome of these proceedings with certainty, management believes that the likelihood of an unfavorable outcome in any pending legal or regulatory proceeding having a material impact, individually or in the aggregate, is neither reasonably possible nor probable of occurring. Item 4. Mine Safety Disclosures Not applicable. 57 Table of Contents PART II
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Item 4. Mine Safety Disclosures Not applicable. 58 Table of Contents PART II

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

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Biggest changeItem 4. Mine Safety Disclosures 58 PART II Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 59 Item 6. Selected Financial Data 61 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 62 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 76 Item 8.
Biggest changeItem 4. Mine Safety Disclosures 57 PART II Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 58 Item 6. Selected Financial Data 60 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 61 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 75 Item 8.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeThe graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends). December 31, 2019 2020 2021 2022 2023 2024 Kosmos Energy Ltd. (KOS) $ 100.00 $ 41.90 $ 61.80 $ 113.50 $ 119.80 $ 61.00 S&P 500 (SPX) 100.00 118.40 152.30 124.70 157.50 196.80 Dow Jones U.S.
Biggest changeThe graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends). December 31, 2020 2021 2022 2023 2024 2025 Kosmos Energy Ltd. (KOS) $ 100.00 $ 147.23 $ 270.64 $ 285.53 $ 145.53 $ 38.61 S&P 500 (SPX) 100.00 128.68 105.36 133.03 166.28 195.98 Dow Jones U.S.
The repurchased share units are reallocated to the number of share units available for issuance under the LTIP. 59 Table of Contents Share Performance Graph The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
The repurchased share units are reallocated to the number of share units available for issuance under the LTIP. 58 Table of Contents Share Performance Graph The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
The following graph illustrates changes over the five-year period ended December 31, 2024, in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index.
The following graph illustrates changes over the five-year period ended December 31, 2025, in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index.
As of February 20, 2025, based on information from the Company’s transfer agent, Computershare Trust Company, N.A., the number of holders of record of Kosmos’ common stock was 132. On February 20, 2025, the last reported sale price of Kosmos’ common stock, as reported on the NYSE, was $3.35 per share. Kosmos does not currently pay a dividend.
As of February 20, 2026, based on information from the Company’s transfer agent, Computershare Trust Company, N.A., the number of holders of record of Kosmos’ common stock was 138. On February 20, 2026, the last reported sale price of Kosmos’ common stock, as reported on the NYSE, was $2.16 per share. Kosmos does not currently pay a dividend.
Exploration & Production Index (DWCEXP) 100.00 66.20 114.10 179.60 187.60 185.20 60 Table of Contents
Exploration & Production Index (DWCEXP) 100.00 172.35 271.20 283.34 279.67 289.76 59 Table of Contents

Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

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Biggest changeItem 6. Selected Financial Data See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” for consolidated financial information as of and for the three years ended December 31, 2024. 61 Table of Contents
Biggest changeItem 6. Selected Financial Data See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” for consolidated financial information as of and for the three years ended December 31, 2025. 60 Table of Contents

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeThe decrease in cash provided by operating activities in the year ended December 31, 2023 when compared to the same period in 2022 is primarily a result of lower average realized oil prices. 68 Table of Contents The following table presents our liquidity and financial position as of December 31, 2024 and 2023: Years Ended December 31, 2024 2023 (In thousands) Outstanding debt principal balances: Facility $ 900,000 $ 925,000 7.125% Senior Notes 250,000 650,000 7.750% Senior Notes 350,000 400,000 7.500% Senior Notes 400,274 450,000 8.750% Senior Notes 500,000 — 3.125% Convertible Senior Notes 400,000 — Total long-term debt $ 2,800,274 $ 2,425,000 Cash and cash equivalents 84,972 95,345 Total restricted cash(1) 305 3,416 Net debt $ 2,714,997 $ 2,326,239 Availability under the Facility $ 450,000 $ 325,000 Availability under the Corporate Revolver $ — $ 250,000 Available borrowings plus cash and cash equivalents $ 534,972 $ 670,345 (1) When our net leverage ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater.
Biggest changeThe decrease in cash provided by operating activities in the year ended December 31, 2024 when compared to the same period in 2023 is primarily a result of increased oil and gas production costs for the year ended December 31, 2024 as a result of pre-production operating costs associated with the GTA Phase 1 project, planned workovers in the Gulf of America business unit, and increased production costs in Equatorial Guinea, together with lower average realized oil prices, offset by changes in working capital. 67 Table of Contents The following table presents our liquidity and financial position as of December 31, 2025 and 2024: Years Ended December 31, 2025 2024 (In thousands) Outstanding debt principal balances: Facility(2) $ 1,200,000 $ 900,000 7.125% Senior Notes(1) 100,000 250,000 7.750% Senior Notes(2) 350,000 350,000 7.500% Senior Notes 400,274 400,274 8.750% Senior Notes 500,000 500,000 3.125% Convertible Senior Notes 400,000 400,000 GoA Term Loan Facility(1) 150,000 — Total long-term debt $ 3,100,274 $ 2,800,274 Cash and cash equivalents 91,518 84,972 Total restricted cash(3) 26,226 305 Net debt $ 2,982,530 $ 2,714,997 Availability under the Facility(2) $ 150,000 $ 450,000 Availability under the GoA Term Loan Facility(1) $ 100,000 $ — Available borrowings plus cash and cash equivalents $ 341,518 $ 534,972 (1) As of December 31, 2025, the undrawn availability under the GoA Term Loan Facility was $100 million, subject to certain conditions on borrowing.
The host contract is the receivable from oil sales at the spot price on the date of sale. The derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale. Exploration and Development Costs.
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 after the sale. Exploration and Development Costs.
Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation, exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation, exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil, natural gas, and LNG and our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following: • the status of our operations in the particular taxing jurisdiction, including whether we have commenced production from a commercial discovery; • whether a commercial discovery has resulted in significant proved reserves that have been independently verified; 74 Table of Contents • the amounts and history of taxable income or losses in a particular jurisdiction; • projections of future income, including the sensitivity of such projections to changes in production volumes and prices; • the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward in a jurisdiction; and • the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets.
When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following: • the status of our operations in the particular taxing jurisdiction, including whether we have commenced production from a commercial discovery; • whether a commercial discovery has resulted in significant proved reserves that have been independently verified; • the amounts and history of taxable income or losses in a particular jurisdiction; • projections of future income, including the sensitivity of such projections to changes in production volumes and prices; • the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward in a jurisdiction; and • the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets.
A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2024 and 2023, we had no oil and gas imbalances recorded in our consolidated financial statements.
A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2025 and 2024, we had no oil and gas imbalances recorded in our consolidated financial statements.
For a discussion of the year ended December 31, 2023 compared to the year ended December 31, 2022, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023.
For a discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024.
The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of December 31, 2024. 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.
The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of December 31, 2025. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
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 capital program for 2025.
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 capital program for 2026.
The Facility has a final maturity date of December 31, 2029. As of December 31, 2024, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.
The Facility has a final maturity date of December 31, 2029. As of December 31, 2025, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.
For the years ended December 31, 2024 and 2023, 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, jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.
For the years ended December 31, 2025 and 2024, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rate applicable to our Ghanaian operations and the 25% statutory tax rate applicable to our Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate, or jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.
As of December 31, 2024 and 2023, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized.
As of December 31, 2025 and 2024, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized.
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.
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 68 Table of Contents result in dilution to our shareholders.
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.
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 69 Table of Contents and financing relationships, considering the stability of the institutions and other aspects of the relationships.
The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental 75 Table of Contents assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves.
The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves.
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 also evaluate potential corporate and asset acquisition and divestment opportunities, 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 have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America (formerly the U.S. Gulf of Mexico). Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success.
We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success.
Certain operating results and statistics for the years ended December 31, 2024, 2023 and 2022 are included in the following tables.
Certain operating results and statistics for the years ended December 31, 2025, 2024 and 2023 are included in the following tables.
As such, our 2025 capital budget is based on our exploitation plans for our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our appraisal and development activities in the Gulf of America, Mauritania and Senegal.
As such, our 2026 capital budget is based on our exploitation plans for our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our development activities in the Gulf of America and in Mauritania and Senegal.
Sao Tome and Principe In April 2024, we received approval for a twelve month extension to May 2025 for the current exploration phase for Block 5 offshore Sao Tome and Principe. 64 Table of Contents Results of Operations All of our results, as presented in the table below, represent operations from Ghana, the Gulf of America, Equatorial Guinea, Mauritania and Senegal.
Sao Tome and Principe In May 2025, we received approval for a twelve month extension to May 2026 for the current exploration phase for Block 5 offshore Sao Tome and Principe. 63 Table of Contents Results of Operations All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal, the Gulf of America.
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 20230 We have one series of senior convertible notes outstanding.
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. 70 Table of Contents 3.125% Convertible Senior Notes due 2030 We have one series of senior convertible notes outstanding.
If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in no benefit for the deferred tax amounts.
If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we 73 Table of Contents would not expect to recover, which would result in no benefit for the deferred tax amounts.
The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations. 2025 Capital Program We estimate we will spend $400 million or less of capital for the year ending December 31, 2025, excluding any acquisitions or divestiture of oil and gas properties during the year.
The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations. 2026 Capital Program We estimate we will spend approximately $350 million of capital for the year ending December 31, 2026, excluding any acquisitions or divestiture of oil and gas properties during the year.
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 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 existing or future subsidiaries. The 3.125% Convertible Senior Notes indenture contains customary terms and covenants.
Net cash provided by operating activities in 2024 was $678.2 million compared with net cash provided by operating activities of $765.2 million in 2023 and $1.1 billion in 2022, respectively.
Net cash provided by operating activities in 2025 was $134.0 million compared with net cash provided by operating activities of $678.2 million in 2024 and $765.2 million in 2023, respectively.
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”).
In connection with the issuance of the 3.125% Convertible Senior Notes, the Company entered into capped call transactions (the “Capped Call Transactions”).
We sold 23,507 MBoe at an average realized price per barrel of oil equivalent of $71.27 in 2024 and 23,057 MBoe at an average realized price per barrel of oil equivalent of $73.80 in 2023. Oil and gas production.
We sold 22,414 MBoe at an average realized price per barrel of oil equivalent of $57.48 in 2025 and 23,507 MBoe at an average realized price per barrel of oil equivalent of $71.27 in 2024. Oil and gas production.
ASC 360 — Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value.
We review our long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360 — Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value.
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 held by our subsidiaries. We were in compliance with the financial covenants contained in the Facility as of September 30, 2024 (the most recent assessment date).
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 held by our subsidiaries.
In October 2024, during the Fall 2024 borrowing base redetermination, the Company’s lending syndicate approved a borrowing base of $1.35 billion. As of December 31, 2024, borrowings under the Facility totaled $900.0 million and the undrawn availability under the facility was $450.0 million. The Facility provides a revolving credit and letter of credit facility.
In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion. As of December 31, 2025, borrowings under the Facility totaled $1.2 billion and the undrawn availability under the facility was $150.0 million.
These amounts are expected to be repaid through the national oil companies’ share of future revenues. 73 Table of Contents Critical Accounting Policies This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States.
Critical Accounting Policies This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States.
In December 2024, we received approval from the Ministry of Hydrocarbons and Mining Development for a twelve month extension to December 2025 for the current exploration phase of Block EG-24.
In October 2025, we received approval from the Ministry of Hydrocarbons and Mining Development for a twelve month extension to December 2026 for the current exploration phase of Block EG-24. In October 2025, we submitted a formal notice to the Ministry of Hydrocarbons and Mining Development that we are electing to exit Block S offshore Equatorial Guinea.
This capital expenditure budget consists of: 69 Table of Contents • Approximately $275 million related to maintenance activities across our Ghana, Equatorial Guinea and Gulf of America assets, including infill development drilling and facilities integrity spend; • Approximately $50 million related to the completion of the first phase of the Greater Tortue Ahmeyim development in Mauritania and Senegal; • Less than $75 million related to progressing our appraisal and development programs in the Gulf of America, Mauritania and Senegal.
This capital expenditure budget consists of: • Approximately $275 million related to maintenance activities across our Ghana and Gulf of America assets, including infill development drilling and TEN FPSO purchase payments; • Approximately $60 million related to progressing our development programs in the Gulf of America and in Mauritania and Senegal; and • Approximately $15 million related to facilities integrity activities in Equatorial Guinea.
Exploration expenses increased by $77.6 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023 primarily as a result of approximately $28.0 million related to the S-6 “Akeng Deep” ILX prospect in Block S offshore Equatorial Guinea which encountered sub-commercial quantities of hydrocarbons and was plugged and abandoned in the fourth quarter of 2024 and approximately $37.2 million of previously capitalized costs related to the Asam discovery in Block S offshore Equatorial Guinea that were written off to exploration expense.
Exploration expenses increased by $103.7 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of approximately $58.5 million of exploration expense related to the Winterfell-4 step out well which was plugged and abandoned during the third quarter of 2025 and approximately $143.7 million of previously capitalized costs related to the Yakaar and Teranga discoveries incurred under the Cayar Offshore Profound Block license that were written off to exploration expense for the year ended December 31, 2025 compared to approximately $28.0 million related to the S-6 “Akeng Deep” ILX prospect in Block S offshore Equatorial Guinea which encountered sub-commercial quantities of hydrocarbons and was plugged and abandoned in the fourth quarter of 2024 and approximately $37.2 million of previously capitalized costs related to the Asam discovery in Block S offshore Equatorial Guinea that were written off to exploration expense for the year ended December 31, 2024, partially offset by decreased seismic, geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.
Oil and gas production costs increased by $140.4 million during the year ended December 31, 2024 as compared to the year ended December 31, 2023 as a result of pre-production operating costs associated with Phase 1 of the GTA project, planned workovers in the Gulf of America business unit and increased production costs in Equatorial Guinea. Exploration expenses.
Oil and gas production costs increased by $178.4 million during the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily as a result of a full year of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal. Exploration expenses.
To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance. Impairment of Long‑lived Assets. We review our long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance. 74 Table of Contents Impairment of Long‑lived Assets.
Interest and other financing costs, net decreased by $7.3 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023 primarily as a result of increased capitalized 66 Table of Contents interest related to the Greater Tortue Ahmeyim Phase 1 project partially offset by increased interest expenses related to higher interest rates and $25.2 million loss on debt modifications and extinguishments for the year ended December 31, 2024 primarily related to the amendment and restatement of the Facility during the second quarter of 2024 and the repurchase of aggregate principal amounts of the 7.125% Senior Notes, the 7.750% Senior Notes, and the 7.500% Senior Notes during the third quarter of 2024.
Interest and other financing costs, net increased by $134.8 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of decreased capitalized interest for the year ended December 31, 2025 related to the GTA Phase 1 project post first gas production in December 2024 partially offset by a $25.2 million loss on debt modifications and extinguishments primarily related to the amendment and restatement of the Facility during the second quarter of 2024.
Years ended December 31, 2024 2023 2022(1) (In thousands, except per volume data) Sales volumes: Oil (MBbl) 20,472 20,385 22,012 Gas (MMcf) 16,180 13,737 4,076 NGL (MBbl) 338 382 426 Total (MBoe) 23,507 23,057 23,117 Total (Boepd) 64,226 63,168 63,335 Revenues: Oil sales $ 1,611,169 $ 1,658,421 $ 2,201,199 Gas sales 57,243 35,307 29,504 NGL sales 6,946 7,880 14,652 Total revenues $ 1,675,358 $ 1,701,608 $ 2,245,355 Average oil sales price per Bbl $ 78.70 $ 81.35 $ 100.00 Average gas sales price per Mcf 3.54 2.57 7.24 Average NGL sales price per Bbl 20.55 20.61 34.39 Average total sales price per Boe 71.27 73.80 97.13 Costs: Oil and gas production, excluding workovers $ 490,860 $ 367,375 $ 387,888 Oil and gas production, workovers 39,654 22,722 21,411 Total oil and gas production costs $ 530,514 $ 390,097 $ 409,299 Depletion, depreciation and amortization $ 456,774 $ 444,927 $ 498,256 Average cost per Boe: Oil and gas production, excluding workovers $ 20.88 $ 15.93 $ 16.78 Oil and gas production, workovers 1.69 0.99 0.93 Total oil and gas production costs 22.57 (2) 16.92 17.71 Depletion, depreciation and amortization 19.43 19.30 21.55 Total oil and gas production costs, depletion, depreciation and amortization $ 42.00 $ 36.22 $ 39.26 (1) Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.
Years ended December 31, 2025 2024 2023 (In thousands, except per volume data) Sales volumes: Oil (MBbl) 16,452 20,472 20,385 Gas (MMcf) 32,280 16,180 13,737 NGL (MBbl) 582 338 382 Total (MBoe) 22,414 23,507 23,057 Total (Boepd) 61,408 64,226 63,168 Revenues: Oil sales $ 1,100,483 $ 1,611,169 $ 1,658,421 Gas sales 170,548 57,243 35,307 NGL sales 17,321 6,946 7,880 Total revenues $ 1,288,352 $ 1,675,358 $ 1,701,608 Average oil sales price per Bbl $ 66.89 $ 78.70 $ 81.35 Average gas sales price per Mcf 5.28 3.54 2.57 Average NGL sales price per Bbl 29.76 20.55 20.61 Average total sales price per Boe 57.48 71.27 73.80 Costs: Oil and gas production, excluding workovers $ 686,039 $ 490,860 $ 367,375 Oil and gas production, workovers 22,863 39,654 22,722 Total oil and gas production costs $ 708,902 (1) $ 530,514 (1) $ 390,097 Depletion, depreciation and amortization $ 556,774 $ 456,774 $ 444,927 Average cost per Boe: Oil and gas production, excluding workovers $ 30.61 $ 20.88 $ 15.93 Oil and gas production, workovers 1.02 1.69 0.99 Total oil and gas production costs 31.63 (1) 22.57 (1) 16.92 Depletion, depreciation and amortization 24.84 19.43 19.30 Total oil and gas production costs, depletion, depreciation and amortization $ 56.47 $ 42.00 $ 36.22 (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.
Oil and gas revenue decreased by $26.3 million during the year ended December 31, 2024 as compared to the year ended December 31, 2023 primarily as a result of lower average realized oil and gas prices partially offset by increased natural gas sales volumes in Ghana for the year ended December 31, 2024.
Oil and gas revenue decreased by $387.0 million during the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily as a result of lower average realized oil and gas prices and lower production resulting in lower sales volume at Jubilee and Equatorial Guinea partially offset by increased sales volumes in Mauritania and Senegal with LNG and condensate cargo sales beginning in 2025.
In December 2024, we submitted a formal notice to the Ministry of Hydrocarbons and Mining Development that we are electing to exit Block 21. 63 Table of Contents In the fourth quarter of 2024, the corporate tax rate in Equatorial Guinea was reduced from 35% to 25%, with an effective date of January 1, 2025.
In February 2026, we notified our partners that we are withdrawing from Block EG-01. 62 Table of Contents In the fourth quarter of 2024, the corporate tax rate in Equatorial Guinea was reduced from 35% to 25%, with an effective date of January 1, 2025.
In October 2024, pursuant to a voluntary cancellation notice sent by the Company, the Corporate Revolver was terminated. 67 Table of Contents Sources and Uses of Cash The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2024, 2023 and 2022: Years Ended December 31, 2024 2023 2022 (In thousands) Sources of cash, cash equivalents and restricted cash: Net cash provided by operating activities $ 678,249 $ 765,170 $ 1,130,476 Net proceeds from issuance of senior notes 885,285 — — Borrowings under long-term debt 325,000 300,000 — Proceeds on sale of assets — — 168,703 1,888,534 1,065,170 1,299,179 Uses of cash, cash equivalents and restricted cash: Oil and gas assets 933,659 932,603 787,297 Acquisition of oil and gas properties — — 22,078 Notes receivable and other investing activities 32,397 62,247 63,183 Payments on long-term debt 350,000 145,000 405,000 Purchase of capped call transactions 49,800 — — Repurchase of senior notes 499,515 — — Dividends — 166 655 Other financing costs 36,647 13,214 9,041 1,902,018 1,153,230 1,287,254 Increase (decrease) in cash, cash equivalents and restricted cash $ (13,484) $ (88,060) $ 11,925 Net cash provided by operating activities.
The change is intended to align the covenant calculation with recent business operations, lower potential oil prices and the impact of operating costs during ramp-up of the GTA Phase 1 project on our results of operations. 66 Table of Contents Sources and Uses of Cash The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2025, 2024 and 2023: Years Ended December 31, 2025 2024 2023 (In thousands) Sources of cash, cash equivalents and restricted cash: Net cash provided by operating activities $ 134,012 $ 678,249 $ 765,170 Net proceeds from issuance of senior notes — 885,285 — Borrowings under long-term debt 675,000 325,000 300,000 809,012 1,888,534 1,065,170 Uses of cash, cash equivalents and restricted cash: Oil and gas assets 314,408 933,659 932,603 Notes receivable and other investing activities 86,791 32,397 62,247 Payments on long-term debt 225,000 350,000 145,000 Purchase of capped call transactions — 49,800 — Repurchase and redemption of senior notes 150,000 499,515 — Dividends — — 166 Other financing costs 346 36,647 13,214 776,545 1,902,018 1,153,230 Increase (decrease) in cash, cash equivalents and restricted cash $ 32,467 $ (13,484) $ (88,060) Net cash provided by operating activities.
The decrease in cash provided by operating activities in the year ended December 31, 2024 when compared to the same period in 2023 is primarily a result of increased oil and gas production costs for the year ended December 31, 2024 as a result of pre-production operating costs associated with Phase 1 of the GTA project, planned workovers in the Gulf of America business unit and increased production costs in Equatorial Guinea, together with lower average realized oil prices, offset by changes in working capital.
The decrease in cash provided by operating activities in the year ended December 31, 2025 when compared to the same period in 2024 is primarily a result of lower average realized oil and gas prices, lower sales volumes in Ghana and Equatorial Guinea, higher oil and gas production costs related to the ramp-up of LNG production at the GTA Phase 1, partially offset by increased sales volumes in Mauritania and Senegal with LNG and condensate cargo sales beginning in 2025 and lower workover expense in Equatorial Guinea.
In September 2024, the Company issued $500.0 million of 8.750% Senior Notes that mature on October 1, 2031. Interest is payable on the 8.750% Senior Notes each April 1 and October 1.
Interest is payable on the 8.750% Senior Notes each April 1 and October 1.
Our next financial covenant assessment date is March 31, 2025, after which date we could be required to restrict approximately $66.0 million in cash as required under the terms of the Facility unless otherwise waived by the lenders.
Our next financial covenant assessment date is March 31, 2026, after which date we will be required to restrict approximately $50.0 million in cash as required under the terms of the Facility unless otherwise waived by the lenders Capital Expenditures and Investments We expect to incur capital costs as we: • drill additional infill wells in Ghana and the Gulf of America; • advance development efforts in the Gulf of America and in Mauritania and Senegal; and • execute facilities integrity activities in Equatorial Guinea.
In September 2024, we added two new lenders to the Facility syndicate, increasing current total commitments by approximately $145.0 million to the full Facility size and borrowing base capacity of $1.35 billion. As of December 31, 2024, borrowings under the Facility totaled $900.0 million and the undrawn availability under the facility was $450.0 million.
As of December 31, 2025, borrowings under the Facility totaled approximately $1.2 billion and the undrawn availability under the facility was $150.0 million. In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion.
Our 7.500% Senior Notes mature on March 1, 2028, and interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 7.750% Senior Notes mature on May 1, 2027, and interest is payable on the 7.750% Senior Notes each May 1 and November 1.
Our 7.500% Senior Notes have an outstanding balance of approximately $400.3 million on December 31, 2025 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 on December 31, 2025 and mature on October 1, 2031.
The Capped Call Transactions cover, initially, the number of shares of our common stock underlying the 3.125% Convertible Senior Notes, subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the 3.125% Convertible Senior Notes. 72 Table of Contents Contractual Obligations The following table presents maturities by expected debt maturity dates, 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.
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. 71 Table of Contents Contractual Obligations The following table presents maturities by expected debt maturity dates, 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.
The operator currently estimates the total remaining commitment to be approximately $137.5 million as of December 31, 2024, net to Kosmos, which will be funded annually by Kosmos over an estimated 12 year period. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.
The operator currently estimates the total remaining commitment to be approximately $122.6 million as of December 31, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated fifteen year period based on the expiration date of the WCTP and DT Petroleum Agreements, which has now been extended to 2040.
Impairment of long-lived assets. Impairment of long-lived assets decreased $222.3 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023. We recorded an impairment charge of $222.3 million in the year ended December 31, 2023 for the TEN Fields as a result of negative proved oil and gas reserve revisions.
As a result of negative proved oil and gas reserves revisions in certain of our Gulf of America fields, primarily Winterfell, we recorded a proved property impairment charge of $177.6 million during the year ended December 31, 2025. Interest and other financing costs, net.
In October 2024, pursuant to a voluntary cancellation notice sent by the Company, the Corporate Revolver was terminated. 70 Table of Contents 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.
We were in compliance with the financial covenants contained in the Facility, as amended, as of September 30, 2025 (the most recent assessment date). The Facility contains customary cross default provisions. The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven.
We used the net proceeds, together with cash on hand, to complete the repurchase of an aggregate principal amount of $400.0 million of the 7.125% Senior Notes, $50.0 million of the 7.750% Senior Notes, and approximately $49.7 million of the 7.500% Senior Notes and to pay expenses related to the issuance of the 8.750% Senior Notes.
The net proceeds were used, together with cash on hand, to fund the redemption of the $250.0 million in aggregate, of the 7.125% Senior Notes due 2026.
Mauritania and Senegal Greater Tortue Ahmeyim Project The Greater Tortue Ahmeyim (GTA) liquefied natural gas (LNG) project achieved first gas production from the subsea system to the FPSO on December 31, 2024. Full commissioning activities of the floating LNG vessel have commenced with first LNG achieved in February 2025.
The GTA LNG project achieved first gas production from the subsea system to the FPSO on December 31, 2024. First LNG was achieved in February 2025 and the first gross LNG cargo was successfully exported in April 2025. Eighteen and a half gross LNG cargos and one condensate cargo were lifted in 2025.
The phased development of the Jubilee Field continued during 2024 bringing three production wells and two water injection wells online during the first half of 2024. We completed the three year infill drilling campaign in Ghana during the second quarter of 2024. The partnership is now conducting a new 4D seismic survey which started in early 2025.
The partnership completed a new 4D seismic survey on the Jubilee and TEN Fields during the first quarter of 2025 and an Ocean Bottom Node survey was completed in the fourth quarter of 2025. In the second quarter of 2025, we commenced the next development drilling campaign in the Jubilee Field.
Year Ended December 31, 2024 vs. 2023 Years Ended December 31, Increase 2024 2023 (Decrease) (In thousands) Revenues and other income: Oil and gas revenue $ 1,675,358 $ 1,701,608 $ (26,250) Gain on sale of assets — — — Other income, net 204 (73) 277 Total revenues and other income 1,675,562 1,701,535 (25,973) Costs and expenses: Oil and gas production 530,514 390,097 140,417 Exploration expenses 119,907 42,278 77,629 General and administrative 100,155 99,532 623 Depletion, depreciation and amortization 456,774 444,927 11,847 Impairment of long-lived assets — 222,278 (222,278) Interest and other financing costs, net 88,598 95,904 (7,306) Derivatives, net 12,099 11,128 971 Other expenses, net 17,703 23,656 (5,953) Total costs and expenses 1,325,750 1,329,800 (4,050) Income before income taxes 349,812 371,735 (21,923) Income tax expense (benefit) 159,961 158,215 1,746 Net income $ 189,851 $ 213,520 $ (23,669) Oil and gas revenue.
Year Ended December 31, 2025 vs. 2024 Years Ended December 31, Increase 2025 2024 (Decrease) (In thousands) Revenues and other income: Oil and gas revenue $ 1,288,352 $ 1,675,358 $ (387,006) Gain on sale of assets 2,200 — 2,200 Other income, net 1,098 204 894 Total revenues and other income 1,291,650 1,675,562 (383,912) Costs and expenses: Oil and gas production 708,902 530,514 178,388 Exploration expenses 223,616 119,907 103,709 General and administrative 76,120 100,155 (24,035) Depletion, depreciation and amortization 556,774 456,774 100,000 Impairment of long-lived assets 177,563 — 177,563 Interest and other financing costs, net 223,430 88,598 134,832 Derivatives, net (53,665) 12,099 (65,764) Other expenses, net 13,491 17,703 (4,212) Total costs and expenses 1,926,231 1,325,750 600,481 Income (loss) before income taxes (634,581) 349,812 (984,393) Income tax expense 65,205 159,961 (94,756) Net income (loss) $ (699,786) $ 189,851 $ (889,637) Oil and gas revenue.
As of December 31, 2024, we expect the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes to be approximately $66.0 million.
(3) 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.
Depletion, depreciation and amortization increased $11.8 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023 due to a higher depletion rate per boe in the Gulf of America and Equatorial Guinea business units as a result of the increased cost basis related to the respective development activities in 2024, partially offset by lower depletion in the current year in our TEN Fields due to the impairment loss recorded during the year ended December 31, 2024.
Depletion, depreciation and amortization increased $100.0 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of the ramp-up of LNG production resulting in first LNG and condensate sales in 2025 at the GTA Phase 1 project in Mauritania and Senegal and higher depletion rates per Boe across our portfolio partially offset by lower sales volumes at Jubilee and Equatorial Guinea. 65 Table of Contents Impairment of long-lived assets.
Years Ending December 31, Asset (Liability) Fair Value at December 31, 2025 2026 2027 2028 2029 Thereafter Total 2024 (In thousands, except percentages) Fixed rate debt: 7.125% Senior Notes $ — $ 250,000 $ — $ — $ — $ — $ 250,000 $ 246,565 7.750% Senior Notes — — 350,000 — — — 350,000 339,927 7.500% Senior Notes — — — 400,274 — — 400,274 379,404 8.750% Senior Notes — — — — — 500,000 500,000 470,965 3.125% Convertible Senior Notes — — — — — 400,000 400,000 332,792 Variable rate debt: Weighted average interest rate 8.51 % 8.93 % 9.14 % 9.66 % 9.88 % — % Facility(1) $ — $ — $ — $ 346,045 $ 553,955 $ — $ 900,000 900,000 Total principal debt repayments $ — $ 250,000 $ 350,000 $ 746,319 $ 553,955 $ 900,000 $ 2,800,274 Interest & commitment fees on long-term debt 264,315 231,889 193,525 148,044 90,639 93,750 1,022,162 Operating leases(2) 4,189 4,260 4,201 3,844 2,808 — 19,302 Purchase obligations(3) 20,821 — — — — — 20,821 Decommissioning trust funds(4) 11,460 11,460 11,460 11,460 11,460 80,218 137,518 Firm transportation commitments 3,472 4,413 2,222 — — — 10,107 ______________________________________ (1) The amounts included in the table represent principal maturities only.
Years Ending December 31, Asset (Liability) Fair Value at December 31, 2026 2027 2028 2029 2030 Thereafter Total 2025 (In thousands, except percentages) Fixed rate debt: 7.125% Senior Notes(5) $ 100,000 $ — $ — $ — $ — $ — $ 100,000 $ 99,303 7.750% Senior Notes(6) — 350,000 — — — — 350,000 321,394 7.500% Senior Notes — — 400,274 — — — 400,274 270,125 8.750% Senior Notes — — — — — 500,000 500,000 283,575 3.125% Convertible Senior Notes — — — — 400,000 — 400,000 172,704 Variable rate debt: Weighted average interest rate 8.15 % 8.24 % 8.91 % 9.34 % — % — % Facility(1)(6) $ — $ 320,449 $ 385,508 $ 494,043 $ — $ — $ 1,200,000 1,200,000 GoA Term Loan Facility(5) 32,143 42,857 42,857 32,143 — — 150,000 150,000 Total principal debt repayments $ 132,143 $ 713,306 $ 828,639 $ 526,186 $ 400,000 $ 500,000 $ 3,100,274 Interest & commitment fees on long-term debt 229,905 203,158 140,351 87,655 50,000 43,750 754,819 Operating leases(2) 3,923 3,956 3,744 3,176 — — 14,799 Purchase obligations(3) 18,702 — — — — — 18,702 Decommissioning trust funds(4) 11,598 8,284 8,284 8,284 8,284 77,865 122,599 Firm transportation commitments 4,180 2,363 — — — — 6,543 ______________________________________ (1) The amounts included in the table represent principal maturities only.
The third development well was drilled in the second quarter of 2024 and brought online in October 2024. Shortly after startup of the third well, production at the field was curtailed due to sand production from the third well seen at the production facility.
In January 2026, Kosmos was awarded two lease blocks in the Gulf of America Big Beautiful Gulf Lease Sale 1 (“BBG1”). At Winterfell, in October 2024, shortly after startup of the Winterfell-3 well, production at the field was curtailed due to sand production from the Winterfell-3. Production from the first two wells was restored in December 2024.
In December 2024, production from Winterfell-1 and Winterfell-2 was restored and remediation work on Winterfell-3 is currently underway. We expect production to be restored at Winterfell-3 in the first quarter of 2025.
Remediation work on Winterfell-3 was performed in the first quarter of 2025, however, it was unsuccessful. Winterfell-3 was temporarily plugged and abandoned during the first quarter of 2025 while the partnership evaluated options to restore production from the Winterfell-3 fault block.
(2) Includes $93.4 million of oil and gas production costs incurred during 2024 before production commenced at the GTA Phase 1 project in Mauritania and Senegal. 65 Table of Contents The discussion of the results of operations and the period‑to‑period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.
Production costs per Bcf in Mauritania and Senegal was $14.68 for the year ended December 31, 2025. Mauritania and Senegal LNG sales are presented as gas sales in the table. 64 Table of Contents The discussion of the results of operations and the period‑to‑period comparisons presented below analyze our historical results.
Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.
Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments. Senior Notes We have three series of senior notes outstanding, which we collectively refer to as the “Senior Notes.” Our 7.750% Senior Notes have an outstanding balance of $350.0 million as of December 31, 2025 and mature on May 1, 2027.
Removed
Recent Developments Corporate In March 2024, the Company issued $400.0 million of 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.
Added
Recent Developments Corporate On September 24, 2025, the Company entered into a senior secured term loan credit agreement secured by first priority liens on all of the Company’s Gulf of America assets (as defined in the Credit Agreement).
Removed
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 equivalent to an initial conversion price of approximately $7.02 per share of our common stock), subject to adjustments.
Added
The GoA Term Loan Facility is a four-year term loan structured into two tranches, with the first tranche a principal amount of $150.0 million, which was funded in October 2025, and a second tranche of an additional $100.0 million, which was funded in January 2026.
Removed
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 the Capped Call Transactions.
Added
The net proceeds were used, together with cash on hand, to fund the redemption of the 7.125% Senior Notes due 2026 totaling $250.0 million in aggregate. The GoA Term Loan Facility is now fully drawn and matures in 2029, with principal payments beginning June 30, 2026.
Removed
In April 2024, in conjunction with the Spring borrowing base redetermination, the Company executed an amendment and restatement of the Facility. As amended and restated, the Facility size and borrowing base capacity is approximately $1.35 billion (increased from $1.25 billion) and was capped by total commitments of approximately $1.21 billion as of June 30, 2024.
Added
On January 16, 2026, the Company announced the pricing of $350.0 million aggregate principal amount of 11.250% senior secured bonds due 2031 in the Nordic market (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 that own the Mauritania and Senegal assets.
Removed
In September 2024, we added two new lenders to the Facility syndicate, increasing current total commitments by approximately $145.0 million to the full Facility size and borrowing base capacity of $1.35 billion. In September 2024, the Company issued $500.0 million of 8.750% Senior Notes and received net proceeds of approximately $494.9 million after deducting fees.
Added
In February 2026, Kosmos used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of its 7.750% Senior Notes due 2027 and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility, with the remaining proceeds to be used for future retirements of the 7.750% Senior Notes due 2027.
Removed
In October 2024, pursuant to a voluntary cancellation notice sent by the Company, the Corporate Revolver was terminated. Ghana During the year ended December 31, 2024, Ghana production averaged approximately 120,900 Boepd gross (41,300 Boepd net).
Added
In July 2025, new U.S. tax legislation was signed into law in the United States known as the “One Big Beautiful Bill Act” or “OBBBA”. The legislation includes a broad range of U.S. corporate tax reform provisions affecting businesses across numerous industries. The necessary adjustments have been reflected for the year ended December 31, 2025.
Removed
In December 2024, the partnership entered into a drilling rig contract for the next development drilling campaign in the Jubilee Field, which is expected to commence in the second quarter of 2025.
Added
Based on our evaluation, we have determined that the impact of OBBBA is not material to the Company’s financial position or results. Ghana During the year ended December 31, 2025, Ghana production averaged approximately 93,100 Boepd gross (31,100 Boepd net).
Removed
The campaign is planned to include the drilling and completion of two in-fill wells in the Jubilee Field in 2025, both expected to be online in the third quarter of 2025.
Added
The Jubilee drilling progressed during the year bringing one producer well successfully online in July 2025. After undergoing scheduled maintenance, the rig returned to the Jubilee Field to drill an additional producer well, which was successfully completed and brought online in January 2026.
Removed
The rig will then undergo scheduled maintenance before returning for a planned four-well drilling campaign on Jubilee in 2026. 62 Table of Contents During 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana.
Added
The development drilling campaign will continue in 2026 by drilling four planned producer wells and an additional water injector well. In June 2025, the Jubilee and TEN partnerships entered into a Memorandum of Understanding with the Government of Ghana to extend to 2040 the WCTP and the DT licenses, which cover the Jubilee and TEN fields offshore Ghana.
Removed
This interim gas sales agreement has been extended to November 2025 at a price of approximately $3.00 per MMBtu. Gulf of America During the year ended December 31, 2024, Gulf of America production averaged approximately 15,300 Boepd (net) (~83% oil).
Added
The Ghana partnership received Government approval in December 2025 for the license extensions. Accordingly, the WCTP and DT licenses have been extended to 2040 and starting from July 2036, Ghana National Petroleum Corporation’s share in the fields will increase by an additional 10% interest and the joint venture partners’ shares will decrease pro rata.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

11 edited+0 added−0 removed5 unchanged
Biggest changeWeighted Average Price per Bbl Term Type of Contract Index MBbl Net Deferred Premium Payable/(Receivable) Swap Sold Put Floor Ceiling Asset (Liability) Fair Value at December 31, 2024(1) 2025: Jan - Jun Two-way collars Dated Brent 2,000 0.50 — — 70.00 85.00 $ 1,592 Jan - Jun Swaps Dated Brent 2,000 — 75.48 — — — $ 2,919 Jan - Dec Two-way collars Dated Brent 2,000 1.00 — — 70.00 85.00 $ 2,715 ______________________________________ (1) Fair values are based on the average forward oil prices on December 31, 2024.
Biggest changeWeighted Average Price per Bbl Term Type of Contract Index MBbl Net Deferred Premium Payable/(Receivable) Swap Sold Put Floor Ceiling Asset (Liability) Fair Value at December 31, 2025(1) 2026: Jan - Jun Two-way collars Dated Brent 1,000 $ 1.55 $ — $ — $ 60.00 $ 74.75 $ 1,002 Jan - Dec Three-way collars Dated Brent 2,000 — — 50.00 60.00 75.51 4,084 Jan - Jun Swaps(1) Dated Brent 1,000 — 72.90 — — 80.00 12,006 Jan - Dec Swaps(1) Dated Brent 1,000 — 72.46 — — 80.00 11,352 Jan - Dec Swaps(1) Dated Brent 2,000 — 69.70 55.00 — — 13,347 Jan - Dec Swaps(1) NYMEX WTI 1,500 — 64.83 50.00 — — 8,706 ______________________________________ (1) Includes call option contracts sold to counterparties to enhance Swaps.
Commodity Price Sensitivity The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of December 31, 2024. Volumes and weighted average prices are net of any offsetting derivatives entered into.
Commodity Price Sensitivity The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of December 31, 2025. Volumes and weighted average prices are net of any offsetting derivatives entered into.
The weighted average interest rate on this indebtedness was approximately 8.4%, 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.
The weighted average interest rate on this indebtedness was approximately 7.7%, 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.
At December 31, 2024, our open commodity derivative instruments were in a net asset position of $7.2 million. As of December 31, 2024, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre‑tax earnings by approximately $27.3 million. Similarly, a hypothetical 10% price decrease would increase future pre‑tax earnings by approximately $30.5 million.
At December 31, 2025, our open commodity derivative instruments were in a net asset position of $50.5 million. As of December 31, 2025, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre‑tax earnings by approximately $36.7 million.
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.
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.
Substantially all of our oil sales are indexed against Dated Brent and Heavy Louisiana Sweet. Oil prices during 2024 ranged between $70.56 and $93.35 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during 2024.
Substantially all of our oil sales are indexed against Dated Brent and Heavy Louisiana Sweet. Oil prices during 2025 ranged between $60.20 and $83.06 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during 2025.
In January 2025, we entered into Dated Brent three-way collar contracts for 2.0 MMBbl from January 2025 through December 2025 with a sold put price of $55.00 per barrel, a floor price of $70.00 per barrel and a ceiling price of $85.00 per barrel.
In January 2026, we entered into Dated Brent three-way collar contracts for 2.0 MMBbl from January 2027 through December 2027 with a weighted average sold put price of $47.50 per barrel, a floor price of $60.00 per barrel and a ceiling price of $75.00 per barrel.
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year ended December 31, 2024: Derivative Contracts Assets (Liabilities) Commodities Interest Rates Total (In thousands) Fair value of contracts outstanding as of December 31, 2023 $ 6,765 $ — $ 6,765 Changes in contract fair value (16,949) 2,202 (14,747) Contract maturities 19,652 — 19,652 Fair value of contracts outstanding as of December 31, 2024 $ 9,468 $ 2,202 $ 11,670 76 Table of Contents Commodity Price Risk The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile.
Financial Statements and Supplementary Data—Note 2—Accounting Policies, Note 9—Derivative Financial Instruments and Note 10—Fair Value Measurements” for a description of the accounting procedures we follow relative to our derivative financial instruments. 75 Table of Contents The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year ended December 31, 2025: Derivative Contracts Assets (Liabilities) Commodities Interest Rates Total (In thousands) Fair value of contracts outstanding as of December 31, 2024 $ 9,468 $ 2,202 $ 11,670 Changes in contract fair value 44,171 837 45,008 Contract maturities (3,142) (3,039) (6,181) Fair value of contracts outstanding as of December 31, 2025 $ 50,497 $ — $ 50,497 Commodity Price Risk The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile.
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” for a description of the accounting procedures we follow relative to our derivative financial instruments.
In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8.
If the floating market rate increased 10% at this level of floating rate debt, we would pay an estimated additional $3.9 million of interest expense per year on the Facility. The impact of the 2025 fixed interest rate swap would reduce the estimated additional interest expense to $1.7 million for the twelve months ending December 31, 2025.
If the floating market rate increased 10% at this level of floating rate debt, we would pay an estimated additional $4.9 million of 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.
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 as of December 31, 2024 totaled $900.0 million, of which $400.0 million bore interest at floating rates after consideration of our fixed interest rate swap.
Similarly, a hypothetical 10% price decrease would increase future pre‑tax earnings by approximately $36.2 million. 76 Table of Contents 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 December 31, 2025 totaled $1.35 billion.

Other KOS 10-K year-over-year comparisons