Kosmos Energy Ltd.

Net proved oil and gas reserve estimates presented were prepared by Ryder Scott Company, L.P. (“RSC”) for the years ended December 31, 2025, 2024 and 2023. RSC are independent petroleum engineers located in Houston, Texas. RSC has prepared the reserve estimates presented herein and meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum engineers for their reserves estimation process.

Net Proved Developed and Undeveloped Reserves

The following table is a summary of net proved developed and undeveloped oil and gas reserves to Kosmos’ interests in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America.

(1)The sum of proved developed reserves and proved undeveloped reserves may not add to net proved developed and undeveloped reserves as a result of rounding.

(2)The revisions in estimates in 2025 are related to:

•In Ghana, Jubilee had a positive revision of 17.9 MMBbl and 13.7 Bcf based on the license extension and update to the Petroleum Agreement amendments, which facilitate additional field development, as well as a positive revision of 22.8 Bcf related to the updated GSA. The net production in Jubilee for the year ended December 31, 2025 was 8.1 MMBbl and 13.9 Bcf. TEN had a negative revision of 0.4 MMBbl and 0.7 Bcf based on field performance, in addition to the net TEN production of 1.1 MMBbl and 0.7 Bcf. Overall, for the year ended December 31, 2025, Jubilee had an increase in reserves of 9.8 MMBbl and 22.6 Bcf and TEN had a decrease in reserves of 1.5 MMBbl and 1.5 Bcf. We note that the decrease in commodity prices did not result in revisions of estimates.

•In Equatorial Guinea, we had a reserves decrease of 1.3 MMBbl from the loss of uneconomic PUD volume and 1.1 MMBbl and 0.2 Bcf due to performance in Ceiba, partially offset by reserves increase due to performance in Okume of 1.2 MMBbl and 0.7 Bcf. The commodity price effect resulted in a loss of 2.4 MMBbl and 3.3 Bcf in Ceiba and 0.4 MMBbl and 0.6 Bcf in Okume. The net production for the year ended December 31, 2025 was 0.9 MMBbl and 0.4 Bcf in Ceiba and 1.7 MMBbl and 0.7 Bcf in Okume. Overall, Equatorial Guinea had a decrease in reserves of 6.6 MMBbl and 4.5 Bcf.

•In Mauritania and Senegal, we had a positive revision of 52.8 Bcf due to increase in the annual production capacity from 2.45 to 2.7 MTPA for the duration of the field life based on realized production volumes and operator plan Greater Tortue Ahmeyim Phase 1 project. This increase is offset by a a negative revision of 51.3 Bcf due to the delay in initial production and ramp up at the beginning of SPA term. The net production for the year ended December 31, 2025 was 0.3 MMBbl and 17.2 Bcf. Overall, there was a decrease in reserves in Mauritania and Senegal of 0.2 MMBbl and 15.8 Bcf. We note that the decrease in commodity prices did not result in revisions of estimates.

•In the Gulf of America, we had a positive reserves revision of 6.2 MMBbl and 1.1 Bcf primarily driven by performance in Kodiak, Tornado, and Odd Job, partially offset by a negative reserves revision in Winterfell due to performance of 2.4 MMBbl and 0.5 Bcf. Change in the plan of development in Marmalard resulted in a negative revision of 1.1 MMBbl and 1.7 Bcf. The net production for the year ended December 31, 2025 was 5.8 MMBbl and 3.7 Bcf. Overall, for the year ended December 31, 2025, the Gulf of America had a reserves decrease of 3.2 MMBbl and 4.9 Bcf. We note that the revision of reserves related to the commodity prices decrease was negligible.

The revisions in estimates in 2024 are related to:

•In Ghana, Jubilee had a negative revision of 5.4 MMBbl and 12.7 Bcf due to field performance primarily related to the J-69 & J-68 wells, partially offset by the positive revision of 4.4 MMBbl and 5.7 Bcf due to drilling of two wells that had no prior proved recognition, in addition to Jubilee net production of 11.7 MMBbl and 13.7 Bcf. TEN had a negative revision of 2.6 MMBbl driven by removal of future development opportunities from the TEN Fields and a small positive revision of 0.9 Bcf of gas due to extension in the field life, in addition to the net TEN production of 1.3 MMBbl and 0.9 Bcf. Overall, for the year ended December 31, 2024, Jubilee had a decrease in reserves of 12.7 MMBbl and 20.7 Bcf and TEN had a decrease in reserves of 4.0 MMBbl. We note that the decrease in commodity prices did not result in revisions of estimates.

•In Equatorial Guinea, we had a reserves decrease of 2.5 MMBbl and 3.3 Bcf primarily from the loss of uneconomic PUD volume in Okume with an additional decrease from net production of 1.3 MMBbl and 0.6 Bcf in Ceiba and 1.9 MMBbl and 0.9 Bcf in Okume. Overall, Equatorial Guinea had a decrease in reserves of 5.7 MMBbl and 4.7 Bcf. We note that the decrease in commodity prices did not result in revisions of estimates.

•In Mauritania and Senegal, we had a positive revision of 0.2 MMBbl and 4.2 Bcf due change in the calculated net reserves amount based on the updated economic parameters as part of the petroleum contract calculations of the Greater Tortue Ahmeyim Phase 1 project. We note that the decrease in commodity prices did not result in revisions of estimates.

•In the Gulf of America, we had a positive reserves revision of 3.2 MMBbl and 2.1 Bcf due to Winterfell performance and an updated plan of development for Marmalard, in addition to an extension of 1.2 MMBbl and 0.2 Bcf based on the results of the drilled Winterfell-3 well, offset by the net production of 5.0 MMBbl and 3.7 Bcf. Overall, for the year ended December 31, 2024, the Gulf of America had a reserves decrease of 0.6 MMBbl and 1.5 Bcf. We note that the decrease in commodity prices did not result in revisions of estimates.

The revisions in estimates in 2023 are related to:

•In Ghana, Jubilee had a positive revision of 14.3 MMBbl and 125.1 Bcf primarily due to positive field performance, the addition of gas sales recognition and positive drilling results, offset by Jubilee net production of 11.2 MMBbl and 9.7 Bcf. TEN had a negative revision of 7.8 MMBbl and 28.4 Bcf primarily driven by a change in the partnership’s development work scope for the TEN Fields and well performance as well as net TEN production of 1.3 MMBbl. Overall, for the year ended December 31, 2023, Jubilee had an increase in reserves of 3.1 MMBbl and 115.3 Bcf and TEN had a decrease in reserves of 9.1 MMBbl and 28.4 Bcf. We note that the decrease in commodity prices did not result in revisions of estimates.

•In Equatorial Guinea, we had a commodity price-related reserves decrease of 0.3 MMBbl and 0.6 Bcf in Ceiba and 0.2 MMBbl and 0.3 Bcf in Okume, with an additional decrease from net production of 0.9 MMBbl and 0.5 Bcf in Ceiba and 2.3 MMBbl and 0.9 Bcf in Okume. Production performance and topsides optimization resulted in an increase of 1.5 MMBbl and 1.6 Bcf in Ceiba and an increase of 1.6 MMBbl and 0.3 Bcf in Okume. Removal of one of the wells from the development plan in Okume resulted in reserves decrease of 0.3 MMBbl. Overall, Equatorial Guinea had a decrease in reserves of 1.0 MMBbl and 0.4 Bcf.

•In Mauritania and Senegal, we had a positive revision of 9.7 Bcf due to the optimization of the timing of the Greater Tortue Ahmeyim Phase 1 project. We also had a negative revision of 0.4 MMBbl of condensate based on the incorporation of well test results. We note that the decrease in commodity prices did not result in revisions of estimates.

•In the Gulf of America, we had a negative reserves revision of 1.8 MMBbl and 2.1 Bcf due to increased watercut at Tornado, production performance at Odd Job and the results of the new well in Marmalard, in addition to commodity price effect of 0.1 MMBbl and 0.1 Bcf, and the net production of 4.9 MMBbl and 4.0 Bcf. Overall, for the year ended December 31, 2023, the Gulf of America had a reserves decrease of 6.8 MMBbl and 6.2 Bcf.

(3)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.

(4)The revisions in estimates in 2025 are related to:

•In Ghana, we converted 14.4 MMBbl and 14.0 Bcf of proved undeveloped reserves to proved developed with the drilling of two wells in Jubilee at a cost of approximately $61.0 million. License extension, an update to the Petroleum Agreement amendments, facilitating additional field development, and an update to the GSA resulted in a positive revision of 29.8 MMBbl and 34.2 Bcf.

•In Equatorial Guinea, we had a negative revision of 1.3 MMBbl in Ceiba due to loss of uneconomic PUD.

•In Mauritania and Senegal, we spent approximately $49.1 million related to the completion of the first phase of the Greater Tortue Ahmeyim development. With the start up of production of three previously drilled wells in the Greater Tortue Ahmeyim Phase 1 project, 4.3 MMBbl and 357.8 Bcf of proved undeveloped reserves were converted to proved developed.

•In the Gulf of America, we converted 0.2 MMBbl and 0.4 Bcf at a cost of approximately $6.2 million by drilling a sidetrack in Marmalard. In addition, we had a negative reserves revision of 1.1 MMBbl and 1.7 Bcf in Marmalard due to the change in the plan of development, and a reserves revision of 0.7 MMBbl and -0.7 Bcf, driven primarily by the addition of a planned sidetrack in Winterfell.

The changes in proved undeveloped reserves in 2024 are related to:

•In Ghana, we converted 13.9 MMBbl and 14.7 Bcf of proved undeveloped reserves to proved developed with the drilling of three wells in Jubilee at a cost of approximately $42.6 million. We also drilled two wells at a cost of $62.7 million that did not convert proved developed reserves as the wells did not have any proved recognition in the prior year. Optimization of future well forecasts in Jubilee resulted in a positive revision of 7.4 MMBbl, offset by the negative adjustment of the sales gas forecast of 1.8 Bcf in Jubilee and a negative revision of 3.2 MMBbl due to removal of additional planned development at TEN.

•In Equatorial Guinea, we converted 1.8 MMBbl of proved undeveloped reserves to proved developed reserves at a cost of $142.6 million by drilling of two wells. We also had a negative revision of 2.7 MMBbl in Okume due to loss of uneconomic PUD, partially offset by a positive revision of 1.3 MMBbl in Ceiba with an addition of two undeveloped wells.

•In Mauritania and Senegal, we spent approximately $310.9 million progressing the Greater Tortue Ahmeyim Phase 1 project. We had a positive revision of 0.2 MMBbl and 4.2 Bcf due to the change in the calculated net reserves amount based on the updated economic parameters as part of the petroleum contract calculations of the Greater Tortue Ahmeyim Phase 1 project.

•In the Gulf of America, we converted 1.2 MMBbl and 1.6 Bcf at a cost of approximately $42.6 million with the installation of the subsea pump in Odd Job. In addition, we converted 2.7 MMBbl and 1.0 Bcf with the completion of two wells in the Winterfell Field at a cost of $78.9 million. We also had a positive revision of 0.8 MMBbl and 1.6 Bcf due to the addition of two undeveloped wells in Marmalard.

The changes in proved undeveloped reserves in 2023 are related to:

•In Ghana, we converted 21.5 MMBbl of proved undeveloped reserves to proved developed reserves during the year by the drilling of five wells in Jubilee at a cost of approximately $98.0 million as well as approximately $91.3 million in subsea costs. In addition, we spent $40.5 million in drilling costs towards wells that we expect to report as converted proved undeveloped reserves in 2024. Positive drilling results during the year ended December 31, 2023 resulted in an increase in proved undeveloped reserves of 0.6 MMBbl and 0.4 Bcf. In Jubilee, the recognition of gas sales resulted in a proved undeveloped reserves increase of 56.0 Bcf and positive revision of future well forecasts based on improved performance of existing wells resulted in a proved undeveloped reserves increase of 16.7 MMBbl. Changes to the partnership’s development work scope and forecasts of planned wells in TEN resulted in proved undeveloped reserves decrease of 4.9 MMBbl and 8.7 Bcf.

•In Equatorial Guinea, during the year ended December 31, 2023, we had a proved developed reserves decrease of 0.3 MMBbl due to removal of one of the planned wells from the Okume drilling plan.

•In Mauritania|Senegal, we had a proved undeveloped reserves increase of 9.7 Bcf due to optimization of the timing of the Greater Tortue Ahmeyim Phase 1 project. We also had a negative revision of 0.4 MMBbl of condensate based on the testing results of the drilled wells. We spent approximately $259.8 million progressing the Greater Tortue Phase 1 development.

•In the Gulf of America, we had a proved undeveloped reserves decrease of 0.9 MMBbl and 0.9 Bcf. We converted 0.6 MMBbl and 0.8 Bcf with the drilling of one well in Marmalard at a cost of $16.5 million, in addition to a negative revision of 0.2 MMBbl and 0.1 Bcf due to slight changes to the recovery of several fields. In addition, we spent approximately $49.0 million on the Odd Job subsea pump installation and approximately $67.5 million towards the development of the Winterfell Field.

(5)These reserves include the estimated quantity of gas to be exported as LNG from the Greater Tortue Ahmeyim Phase 1 project, Our natural gas reserves in Ghana include natural gas forecasted to be sold to the Government of Ghana. If and when a future long-term gas sales agreement is executed with the Government of Ghana, a portion of the remaining gas may be recognized as reserves.

These natural gas reserves also include the estimated quantities of fuel gas required to operate the Jubilee and TEN FPSOs, the Equatorial Guinea facilities and the Greater Tortue Ahmeyim Phase 1 facilities during normal field operations. 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. 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 for 2025, 1.9 Bcf for 2024 and 1.1 Bcf for 2023.

Net proved reserves were calculated utilizing the twelve month unweighted arithmetic average of the first‑day‑of‑the‑month oil price for each month based on the respective benchmark price in the period January through December 2025. The average price is adjusted for crude handling, transportation fees, quality, and a regional price differential.

Proved oil and gas reserves are defined by the SEC Rule 4.10(a) of Regulation S‑X as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recovered under current economic conditions, operating methods, and government regulations. Inherent uncertainties exist in estimating proved reserve quantities, projecting future production rates and timing of development expenditures.

Capitalized Costs Related to Oil and Gas Activities

The following table presents aggregate capitalized costs related to oil and gas activities:

Costs Incurred in Oil and Gas Activities

The following tables reflects total costs incurred, both capitalized and expensed, for oil and gas property acquisition, exploration, and development activities for the year.

(1) Excludes $96.6 million reduction of capitalized asset retirement costs primarily related to the license extension of the WCTP and DT Petroleum Agreements in Ghana in December 2025 and changes in estimated timing of work.

Standardized Measure for Discounted Future Net Cash Flows

The following table provides projected future net cash flows based on the twelve month unweighted arithmetic average of the first‑day‑of‑the‑month oil price for Brent crude in the period January through December 2025. The average price is adjusted for crude handling, transportation fees, quality, and a regional price differential.

Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on market conditions that occur.

The projection should not be interpreted as representing the current value to Kosmos. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Kosmos’ investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a wide range of different price and cost assumptions.

The standardized measure is intended to provide a better means to compare the value of Kosmos’ proved reserves at a given time with those of other oil producing companies than is provided by comparing raw proved reserve quantities.

Changes in the Standardized Measure for Discounted Cash Flows