Kosmos Energy Ltd. (KOS) Business

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. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol KOS.

Kosmos was founded in 2003 to find oil and gas in under‑explored or overlooked parts of West Africa. 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). Jubilee was one of the largest oil discoveries worldwide in 2007 and is considered one of the largest finds offshore West Africa discovered during that decade. The Greater Tortue Ahmeyim discovery was one of the largest natural gas discoveries worldwide in 2015 and is one of the largest gas discoveries ever offshore West Africa.

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. 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. 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.

Our Business Strategy

As a full-cycle deepwater E&P company, our mission is to safely deliver production and free cash flow from a portfolio rich in opportunities through a disciplined allocation of capital and optimal portfolio management for the benefit of our shareholders and stakeholders. As a responsible company, we are working to supply the energy the world needs today, find and develop affordable and cleaner energy to advance the energy transition, and be a force for good in our host countries.

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. 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. In addition, our portfolio contains an inventory of infrastructure-led exploration prospects, which we plan to continue to mature and high-grade for future drilling and development, providing us access to additional high return growth potential in the coming years. 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.

Grow cash flow, proved reserves and production through exploitation and development with increasing exposure to natural gas and LNG

We plan to grow cash flow, proved reserves and production by further exploiting our fields offshore Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America. In Ghana, we plan to maintain a consistent drilling program, bringing additional development wells online at the Jubilee Field in the near term, supported by high facility uptime and sustained water injection. In the Gulf of America, we plan to continue development drilling and well work in existing fields, and progressing the Tiberius project as a phased development. Offshore Mauritania and Senegal, growth is expected to be realized through additional development beyond GTA Phase 1 by fully utilizing the existing infrastructure.

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Focus on optimally developing our discoveries to initial production

Our approach to development is designed to deliver first production on an accelerated timeline, with low cost, lower carbon solutions, where we can leverage early learnings to improve future outcomes and maximize returns. In certain circumstances, we believe a phased approach can be employed to optimize full‑field development. A phased approach facilitates refinement of the development plans based on experience gained in initial phases of production and by leveraging existing infrastructure as subsequent phases of development are implemented. Production and reservoir performance from the initial phases are monitored closely to determine the most efficient and effective techniques to maximize the recovery of reserves and returns. Other benefits include minimizing upfront capital costs, reducing execution risks through smaller initial infrastructure requirements, and enabling cash flow from the initial phases of production to fund a portion of capital costs for subsequent phases. Our development of the Jubilee Field is an example of this approach. The GTA development is also being developed in a phased approach, consistent with our business strategy. Finally, our approach to discoveries in the Gulf of America is to develop them via subsea tie-back to existing host facilities with spare capacity, which reduces development costs and the average timeline to first production. The Winterfell discovery (2021) is an example of this approach, with development achieving first production around three years after initial discovery. In addition, we anticipate that the Tiberius discovery (2023) will follow a similar approach.

Apply our entrepreneurial culture, which fosters innovation and creativity, to continue our successful exploration and development program

Our employees are critical to the success of our business strategy, and we have created an environment that enables them to focus their knowledge, skills and experience on finding, developing and producing new fields and optimizing production from existing fields. 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. 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.

Our returns focused exploration approach

Our exploration activity, which is deeply rooted in a fundamental, geologic approach, is focused on proven basins with high-graded infrastructure-led prospects and material play extension opportunities. We target specific areas with sufficient size to manage exploration risks and provide scale should the exploration concept prove successful. Alongside the subsurface analysis, Kosmos gains a thorough understanding of the “above‑ground” dynamics in each of the countries in which we operate, which may influence a particular country’s relative desirability from an overall oil and natural gas operating and risk adjusted return perspective.

Our approach is aimed at areas where we have existing production and where there is sufficient infrastructure capacity to enable the development of new discoveries via subsea tieback. Acquisition of assets in the Gulf of America have added high-quality prospectivity to our inventory of infrastructure-led exploration opportunities given their attractive acreage positions within proximity of existing infrastructure with excess capacity available. Existing infrastructure allows us to shorten the time cycle from discovery to first production, lower the capital requirements and increase the returns.

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. These acquisitions were targeted to increase and complement our existing properties, providing production diversification while increasing the quality of investment opportunities in our portfolio. Our experienced team of management and technical professionals intend to continue identifying, evaluating and pursuing transactions involving oil and natural gas properties that are complementary to our core operating areas, as well as opportunities in other basins where we can apply our existing knowledge, expertise and relationships to create shareholder value. Our focus is on transactions where we can leverage our operational experience and expertise to provide productivity and cost improvements, invest in additional developmental opportunities in such assets and implement an infrastructure-led exploration program for nearby prospects. A key attribute we seek in evaluating potential transactions is that they are cash flow accretive and strengthen the balance sheet.

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Secure a premium license to operate through industry-leading ESG performance

We recognize that advancing the societies in which we work and operating in a manner that protects the environment is critical for creating long-term returns. We aim to continuously improve our ESG credentials by working with a range of stakeholders, including shareholders, partners, suppliers, host governments and civil society organizations.

We aim to act as a force for good by advancing a just energy transition in our host countries and communities – namely by supporting economic and social development in the places where we work through supplying affordable and cleaner energy while lowering emissions. We use the United Nations Sustainable Development Goals to understand how our activities promote economic and social progress in host countries. Our business principles reflect our shared values as a company, define how we conduct our business and set the standards to which we hold ourselves accountable. Our business principles are supported by more detailed policies, procedures, and management systems. Each year, we report on our ESG approach and performance in our Sustainability Report and on our website.

Most recently, we have focused on evaluating the costs, benefits, risks, and opportunities that climate change and the global energy transition may present to our business and integrating them into our business strategy. As part of this effort, the Health, Safety, Environment and Sustainability Board Committee oversees our climate change strategy, risk management, policies, targets and performance. Our TCFD (Task Force on Climate related Disclosure) aligned Sustainability Report provides more detail on our management approach to climate change across four categories: Governance, Strategy, Risk Management, and Metrics and Targets. In 2020 we set the goal to achieve operated Scope 1 and Scope 2 carbon neutrality by 2030 or sooner. We first achieved this goal in 2021 and have identified a pathway to help maintain it through continual monitoring of emissions, assessment of emission reduction opportunities, and, for residual emissions, investment in high-quality carbon offset projects. We recognize most of our production, and the associated GHG emissions, is derived from assets in which we are non-operating partners. In 2023 we set a target to reduce absolute Scope 1 equity emissions 25% by 2026, compared to a 2022 baseline. This tangible, near-term target addresses the need to manage the climate impact of our portfolio. Since 2022, together with our partners, we have made significant progress to reduce routine flaring of natural gas for our non-operated assets in Ghana. Further reductions are planned in Ghana and Equatorial Guinea in 2026. In the long-term, we have set the goal to achieve and maintain top quartile carbon intensity of production in both our oil and gas portfolios, demonstrating that our climate strategy is fully aligned with our business strategy.

Maintain financial discipline

Execution of our strategy requires us to maintain a conservative financial approach with a strong balance sheet and ample liquidity. We also plan to remain proactive to ensure we have minimal near-term debt maturities and reduce leverage. As of December 31, 2025, our liquidity was approximately $342 million.

Additionally, we use derivative instruments to partially limit our exposure to fluctuations in oil prices and changes in market interest rates. We have an active commodity hedging program where we aim to hedge a portion of our anticipated sales volumes on a one to two year rolling basis, with the goal to protect against the downside price scenario while still retaining partial exposure to the upside. As of January 31, 2026, we have hedged positions covering approximately 7.6 million barrels of oil production in 2026 and approximately 2.0 million barrels of oil production in 2027. We also maintain insurance to partially protect against loss of production revenues from certain of our key producing assets.

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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. The following tables provide a summary of certain key 2025 data for our geographic areas.

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(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. Production costs per Bcf in Mauritania and Senegal was $14.68 for the year ended December 31, 2025. In Mauritania and Senegal, all condensate sales and LNG sales are associated production from our gas wells.

(2)Includes $93.4 million of pre-production operating costs for the year ended December 31, 2024 incurred before production commenced at the Greater Tortue Ahmeyim Phase 1 project in Mauritania and Senegal. Oil and gas production costs related to the LNG production at the GTA Phase 1 project were $237.6 million for the year ended December 31, 2025. First LNG was achieved in February 2025 and the first LNG cargo was successfully completed in April 2025.

(3)Mauritania and Senegal LNG sales are presented as gas sales in the table.

(4)Totals within the table may not add as a result of rounding.

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Current information about our deepwater fields is summarized in the following table.

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(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. To optimize resource recovery in this field, we entered into the Jubilee UUOA in July 2009 with GNPC and the other block partners of each of these two blocks. The Jubilee UUOA governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP petroleum contract and the DT petroleum contract areas. The interest percentage is subject to redetermination of the participating interests in the Jubilee Field pursuant to the terms of the Jubilee UUOA. Our current paying interest on development activities in the Jubilee Field is 43.05%.

(3)The Ghana partnership received Government approval in December 2025 for the license extension for its WCTP and DT Petroleum Agreements, which cover the Jubilee and TEN fields, to 2040. As part of the extensions, 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.

(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. To optimize resource recovery in this field, we entered into the GTA UUOA in February 2019 with the governments of Mauritania and Senegal and the other block partners of each of these two blocks. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim Field and created the Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint Louis Offshore Profond Block areas. 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.

(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.

(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.

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(9)License expiration date can be extended by an additional ten years subject to certain conditions being met.

(10)License expiration date can be extended by an additional twenty years subject to certain conditions being met.

Exploration License and Lease Areas

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(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.

(2)ANP-STP's carried interest may be converted to a full participating interest at any time. ANP-STP will reimburse any costs, expenses and any amount incurred on its behalf prior to the election.

(3)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.

(4)Our Gulf of America blocks can be held by operations or commercial production, and the corresponding lease periods extend as long as governmental approved operations continue on the relevant block. This can extend the lease expiration to a date later than 2034.

Ghana

The WCTP and DT Blocks are located within the Tano Basin, offshore Ghana. This basin contains a proven world‑class petroleum system as evidenced by our discoveries. In October 2021, Kosmos completed the acquisition of Anadarko WCTP Company (“Anadarko WCTP”), a subsidiary of Occidental Petroleum Corporation, which owned a participating interest in the WCTP Block and DT Block offshore Ghana. 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%. The following is a brief discussion of our discoveries on our license areas offshore Ghana.

In June 2025, the Jubilee and TEN partnerships entered into a Memorandum of Understanding with the Government of Ghana to extend the WCTP and the DT licenses. The Ghana partnership received Government approval in December 2025 for the license extensions, which cover the Jubilee and TEN fields. 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. As part of the extension of the Petroleum Agreements, the Jubilee plan of development is amended to include up to twenty additional wells in the field.

Ghana West Cape Three Points Block

Tullow is the operator of the West Cape Three Points Block. Under the WCTP petroleum contract, Kosmos is required to pay to the Government of Ghana a fixed royalty of 5% and a potential sliding‑scale royalty (“additional oil entitlement”), which comes into effect and escalates as the nominal project rate of return increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the Government of Ghana, in cash. A corporate tax rate of 35% is applied to profits at a country level. The WCTP petroleum contract has an original duration of 30 years from its effective date (July 2004), which has now been extended to 2040.

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Ghana Deepwater Tano Block

Tullow is the operator of the Deepwater Tano Block. Under the DT petroleum contract, GNPC exercised its option to acquire an additional paying interest of 5% in the commercial discovery with respect to the Jubilee Field development and the TEN Fields development. Kosmos is required to pay to the Government of Ghana a fixed royalty of 5% and a potential additional oil entitlement, which comes into effect and escalates as the nominal project rate of return increases above a certain threshold. These royalties are to be paid in‑kind or, at the election of the Government of Ghana, in cash. 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.

The Ghanaian Petroleum Exploration and Production Law of 1984 (PNDCL 84) (the “1984 Ghanaian Petroleum Law”) and the WCTP and DT petroleum contracts form the basis of exploration, development and production operations on the WCTP and DT blocks. Pursuant to these petroleum contracts, most significant decisions, including PoDs and annual work programs, for operations other than exploration and appraisal, must be approved by a joint management committee, consisting of representatives of certain block partners and GNPC. Certain decisions require unanimity.

Jubilee Field

The Jubilee Field was discovered by Kosmos in 2007 by the Mahogany-1 well with first oil produced in 2010. The field covers an area within both the WCTP and DT Blocks. To optimize resource recovery in the Jubilee Field, it was unitized and the Jubilee UUOA was agreed to in 2009 which governs each party’s respective rights and duties in the Jubilee Unit and named Tullow as the Unit Operator. Although the Jubilee Field is unitized, Kosmos’ participating interests in each block outside the boundary of the Jubilee Unit are not impacted by the Jubilee UUOA. Currently, the WCTP petroleum contract has a 54.367% participating interest in the Jubilee Unit and the DT petroleum contract has a 45.633% participating interest in the Jubilee Unit. Our participating interest in the Jubilee Unit is based on these allocations and any event of redetermination in the future would impact Jubilee Unit participating interest.

The Jubilee Field is located approximately 60 kilometers offshore Ghana in water depths of approximately 1,000 to 1,800 meters, which led to the decision to implement an FPSO based development. The FPSO is designed to provide water and natural gas injection to support reservoir pressure, to process and store oil and to export gas through a pipeline to the mainland. The Jubilee Field continues to be developed in a phased approach. The initial phase provided subsea infrastructure capacity for additional production and injection wells to be drilled in future phases of development. The partnership completed a new 4D seismic survey on the Jubilee and TEN Fields during the first quarter of 2025 and an OBN survey was completed in the fourth 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. After undergoing scheduled maintenance, the rig returned to the field and drilled an additional producer well in the Jubilee Field, which was successfully completed and brought online in January 2026. The campaign is planned to include the drilling and completion of an additional four producer wells and an additional water injector well in 2026.

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. This interim gas sales agreement was subsequently extended to November 2025 at a price of approximately $3.00 per MMBtu. In December 2025, as part of the extension of the WCTP and DT Petroleum Agreements, the Ghana partners and Government of Ghana have approved an amended gas sales agreement at a price of $2.50 per MMBtu through the extended expiration date of 2040 for the WCTP and DT licenses. Our inability to continuously 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.

TEN

The TEN Fields are located in the western and central portions of the DT Block, approximately 48 kilometers offshore Ghana in water depths of approximately 1,000 to 1,700 meters. The discoveries have been jointly developed with shared infrastructure and a single FPSO, with first oil produced in 2016. Similar to Jubilee, the TEN Fields have been developed in a phased manner. The TEN PoD was designed to include an expandable subsea system that could provide for multiple phases.

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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. We expand our inventory through the Gulf of America Federal lease sales and farm-in transactions.

The following is a brief discussion of our key fields in the Gulf of America.

Odd Job

The Odd Job Field is producing from three Middle Miocene wells through the Delta House FPS, operated by Murphy. 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.

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”).

Winterfell

The Winterfell Field is producing from two wells in the Upper Miocene sands.The initial two production wells of the first phase were brought online in the third quarter of 2024 and the Winterfell-3 well was 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 December 2024, production from Winterfell-1 and Winterfell-2 was restored. Remediation work on Winterfell-3 was performed in the first quarter of 2025, however, it was unsuccessful. During the second quarter, the partnership drilled the Winterfell-4 step out well to test a separate fault block and define the eastern extent of the Winterfell reservoir area. The Winterfell-4 well was abandoned in September 2025 by the operator due to challenges during the completion operations arising from the collapse of the production casing. The partnership will continue to review alternative options to access those resources with near-term activity in 2026 focused on restoring production from the Winterfell-3 fault block.

Tiberius

In July 2023, Kosmos spud a well to test the Tiberius infrastructure-led exploration prospect, which is located in block 964 of Keathley Canyon (33.3% working interest) in the Outer Wilcox play. In October 2023, we announced the well encountered approximately 75 meters (250 feet) of net oil pay in the primary Wilcox target. Initial fluid and core analysis supports the production potential of the wells, with characteristics analogous with similar nearby discoveries in the Wilcox trend. In March 2024, Kosmos completed the acquisition of an additional 16.7% participating interest in the Tiberius area in Keathley Canyon Blocks 920 and 964 offshore Gulf of America. As a result of the transaction, Kosmos’ participating interest in Tiberius was increased from 33.3% to 50.0%. Kosmos continues to progress the development plan with our partner Occidental Petroleum Corporation (“Oxy”) (50% working interest). A production handling agreement for the Oxy-Operated Lucius platform was signed in the third quarter of 2025. Final investment decision and a farm down to reduce Kosmos’ working interested are expected in the first half of 2026.

Mauritania

In June 2012, we entered into an exploration and production contract covering offshore Mauritania Block C8 with the Islamic Republic of Mauritania. Petroleum cost recovery is apportioned to the contractor from up to 55% for oil and 62% for gas of total production prior to petroleum profits being split between the Government of Mauritania and the contractor. Petroleum profits are then apportioned based upon “R‑factor” tranches, where the R‑factor is cumulative net revenues divided by the cumulative investment. At the election of the Government of Mauritania, the government may receive its share of production in cash or in kind. A corporate tax rate of 27% is applied to profits at the license level. In June 2022, the exploration period of Block C8 offshore Mauritania expired.

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The C8 block is located on the western margin of the Mauritania Salt Basin offshore Mauritania and ranges in water depths from 100 to 3,000 meters. We have drilled one successful exploration well and one appraisal well in our existing Block C8 acreage (now Greater Tortue Ahmeyim).

Senegal

The Saint Louis Offshore Profond and Cayar Offshore Profond Blocks are located in the Senegal River Cretaceous petroleum system and range in water depth from 300 to 3,100 meters. The area is an extension of the working petroleum system in the Mauritania Salt Basin.

The exploration period of the St. Louis Offshore Profound license expired in July 2021. The current phase of the Cayar Block exploration license expires in July 2026. We have drilled two successful exploration wells (Yakaar-1 and Teranga-1) and one successful appraisal well (Yakaar-2) in the Cayar Offshore Profound Block. Kosmos has worked with PETROSEN on potential development concepts for the field, along with identifying a suitable partner. Given we have not been able to attract a suitable partner and agree a commercially attractive development concept with the government of Senegal, we are working with PETROSEN to withdraw from the block.

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. Mauritania and Senegal agreed that the Greater Tortue Ahmeyim Field would be unitized for optimal resource recovery in the Inter-State Cooperation Agreement (ICA) signed in February 2018. The GTA UUOA was agreed between the contractor groups of the C8 and Saint-Louis Offshore Profond Blocks and approved by the appropriate Ministers in Mauritania and Senegal in February 2019. BP Mauritania and BP Senegal are co-Unit Operator and allocate responsibilities for the initial development of the Greater Tortue Ahmeyim Field. During the second quarter of 2019, SMH and PETROSEN elected to increase their respective interests in their portion of the Greater Tortue Ahmeyim Unit to the maximum allowed percentages under the respective petroleum contracts. 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. In February 2019, Mauritania and Senegal each issued an exploitation authorization for the Greater Tortue Ahmeyim Unit area covered by the GTA UUOA granting the partnership the right to develop and produce gas for an initial period of twenty-five years in Senegal, or 2044, and thirty years in Mauritania, or 2049. The exploration authorizations may be extended by up to twenty years in Senegal and up to ten years in Mauritania.

The Greater Tortue Ahmeyim discoveries are significant, play-opening gas discoveries for the outboard Cretaceous petroleum system and are located approximately 120 kilometers offshore Mauritania and Senegal. The Greater Tortue Ahmeyim development straddles Block C8 offshore Mauritania and Saint Louis Offshore Profond Block offshore Senegal.

We have drilled four exploration and appraisal wells within the GTA development, Tortue-1, Guembeul-1, Ahmeyim-2 and Greater Tortue Ahmeyim-1. The wells penetrated multiple, excellent quality gas reservoirs, including the Lower Cenomanian, Upper Cenomanian and underlying Albian. The wells successfully delineated the Ahmeyim and Guembeul gas discoveries and demonstrated reservoir continuity, as well as static pressure communication between the three wells drilled within the Lower Cenomanian reservoir. The discoveries range in water depths from approximately 2,700 meters to 2,800 meters, with total depths drilled ranging from approximately 5,100 meters to 5,250 meters.

The Tortue-1 discovery well, located in Block C8 offshore Mauritania, intersected approximately 117 meters of net hydrocarbon pay. A single gas pool was encountered in the Lower Cenomanian objective, which is comprised of three reservoirs totaling 88 meters in thickness over a gross hydrocarbon interval of 160 meters. A fourth reservoir totaling 19 meters was penetrated within the Upper Cenomanian target over a gross hydrocarbon interval of 150 meters. The exploration well also intersected an additional 10 meters of net hydrocarbon pay in the lower Albian section.

The Guembeul-1 discovery well, located in the northern part of the Saint Louis Offshore Profond area in Senegal, is located approximately five kilometers south of the Tortue-1 exploration well in Mauritania. The well encountered 101 meters of net gas pay in two excellent quality reservoirs, including 56 meters in the Lower Cenomanian and 45 meters in the underlying Albian, with no water encountered.

The Ahmeyim-2 appraisal well is located in Block C8 offshore Mauritania, approximately five kilometers northwest, and 200 meters down-dip of the basin-opening Tortue-1 discovery. The well confirmed significant thickening of the gross

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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 Greater Tortue Ahmeyim-1 appraisal well, drilled on the eastern anticline within the unit development area of Greater Tortue Ahmeyim field, encountered approximately 30 meters of net gas pay in high quality Albian reservoir. The well was drilled in approximately 2,500 meters of water, approximately 10 kilometers inboard of the Guembeul-1A and Tortue-1 wells, to a total depth of 4,884 meters.

In December 2018, we and our partners announced that a final investment decision for Phase 1 of the Greater Tortue Ahmeyim project had been agreed. The Greater Tortue Ahmeyim Phase 1 project is designed to produce gas from a deepwater subsea system to a mid-water FPSO, which processes the gas to make it liquefaction ready, and sends the gas through a pipeline to a FLNG facility. 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. The project provides LNG for global export, and is also planned to make gas available for domestic use in both Mauritania and Senegal. Following a competitive tender process, BP Gas Marketing (“BPGM”) was selected as the buyer for the LNG offtake for GTA Phase 1, and the Tortue Phase 1 SPA was executed in February 2020 with an initial term through the end of 2033 with a seller’s option to extend the term for an additional 10 years.

First gas production from the subsea system was achieved 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 Gimi FLNG vessel Commercial Operations Date was achieved in the second quarter of 2025 with successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum. Additionally, the Gimi FLNG vessel operated at nameplate capacity in December 2025, reaching a peak production rate of approximately 3.0 million tonnes per annum. Further phases of GTA are expected to increase production through the full utilization of the existing infrastructure.

Equatorial Guinea

As described in Item 7 of this Form 10-K, on February 24, 2026, we entered into a Share Sale and Purchase Agreement with a subsidiary of Panoro Energy ASA for the sale of all of our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. The transaction has received approval from the Government of Equatorial Guinea and completion only remains subject to CEMAC customary approval. While we expect to close the transaction around the middle of 2026, there can be no assurances that closing will ultimately occur or that it may not be delayed. As such, the Company has elected to report on the business throughout this Form 10-K on the basis that the transaction has not yet closed and that the Company continues to own all of the participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. All such references to the Company’s future plans and expectations for the Equatorial Guinea business unit should therefore be read in light of the ongoing transaction.

In June 2018, we closed a farm-in agreement for Block EG-24, offshore Equatorial Guinea, whereby we acquired a 40% non-operated participating interest. In the first quarter of 2019, we acquired the remaining interest in and operatorship of the block, which resulted in Kosmos owning an 80% participating interest in Block EG-24. The Equatorial Guinean national oil company, GEPetrol, currently has a 20% carried interest during the exploration period. 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. In October 2025, we received approval of an extension of the second sub-period to December 2026. Block EG-24 currently comprises approximately 874,012 acres (3,537 square kilometers) and is located in the southern part of the Gulf of Guinea, in the Republic of Equatorial Guinea, west of the Rio Muni petroleum province with water depths up to 2,300 meters.

Ceiba Field and Okume Complex

In Equatorial Guinea, we maintain a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. Trident is the operator of the Ceiba Field and Okume Complex. These offshore assets in the Gulf of Guinea provide cash flow through production.

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.

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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. Under the Block G petroleum contract, Kosmos is required to pay to the Ministry of Hydrocarbons and Mining Development of Equatorial Guinea a percentage of production as a royalty, currently 11%. These royalties are to be paid in‑kind or, at the election of the Ministry of Hydrocarbons and Mining Development of Equatorial Guinea, in cash. A corporate tax rate of 35% is applied to profits at a country level through December 31, 2024. 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.

Sao Tome and Principe

We are the operator for the petroleum contract covering Block 5, offshore Sao Tome and Principe in the Gulf of Guinea. The block covers an area of approximately 527,000 acres (gross) in water depths ranging from 2,150 to 3,000 meters.

Our block is adjacent to, and represents a potential extension of, a proven and prolific petroleum system offshore Equatorial Guinea and northern Gabon comprising Cretaceous post-rift source rocks and Late Cretaceous reservoirs.

In August 2017, we completed a 3D seismic survey of approximately 2,500 square kilometers offshore Sao Tome and Principe. Processing has been completed and the 3D seismic data has been integrated into our geological evaluation. We continue to mature an inventory of prospects on the license area in Sao Tome and Principe and will continue to refine and assess the prospectivity. In May 2025, we received approval to extend the current exploration phase for Block 5 offshore Sao Tome and Principe to May 2026.

Our Reserves

The following table sets forth summary information about our estimated proved reserves as of December 31, 2025. See “Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Data (Unaudited)” for additional information.

Our estimated proved reserves as of December 31, 2025, 2024, and 2023 were associated with our fields in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America.

Summary of Oil and Gas Reserves

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(1)Totals within the table may not add as a result of rounding.

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(2)Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split between the WCTP Block and DT Block.

(3)These reserves include the estimated quantity of gas to be exported as LNG from the Greater Tortue Ahmeyim Phase 1 project, as a result of the Tortue SPA finalized in February of 2020. Our natural gas reserves in Ghana include natural gas forecasted to be sold to the Government of Ghana.

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, 1.9 Bcf and 1.1 Bcf for 2025, 2024, and 2023, respectively.

(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.

(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. Jubilee net production of 10.5 MMBoe was offset by the positive revision of 20.2 MMBoe based on the license extension and Petroleum Agreement amendments, facilitating additional field development. The change to the Gas Sales Agreement (GSA) resulted in a positive revision of 3.8 MMBoe. There were no changes related to the commodity price effect in Jubilee. The TEN net production for the December 31, 2025 was 1.3 MMBoe. Changes at TEN include a negative revision of 0.5 MMBoe due to performance, for an overall decrease in reserves of 1.8 MMBoe. We note that there were no changes related to the commodity price effect.

The overall net reserves at Equatorial Guinea decreased by 7.3 MMBoe. Changes at Equatorial Guinea included negative revisions of 1.3 MMBoe due to loss of uneconomic PUD volumes in Ceiba and 0.1 MMBoe due to performance, in addition to the net production of 2.8 MMBoe. The commodity price effect caused a negative revision of 3.4 MMBoe in Equatorial Guinea.

Changes in Mauritania and Senegal include a positive revision of 8.8 MMBoe 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 for the Greater Tortue Ahmeyim Phase 1 project. This increase is offset by a negative revision of 8.5 MMBoe due to the delay in initial production and ramp up at the beginning of Sale and Purchase Agreement (SPA) term, as well as the net 2025 production of 3.2 MMBoe and a fixed contract length that supports proved reserves recognition. There were no changes related to the commodity price effect on reserves in Mauritania and Senegal. The overall net reserves at Mauritania and Senegal decreased by 2.8 MMBoe.

Changes at the Gulf of America include a positive revision of 6.4 MMBoe driven primarily by the performance in Kodiak, Tornado, and Odd Job, partially offset by a negative change of 2.5 MMBoe due to Winterfell performance. An update to the future development plans for Marmalard caused a negative revision of 1.4 MMBoe. The Gulf of America net production for the year ended December 31, 2025 was 6.4 MMBoe for an overall reserves decrease of 4.0 MMBoe. The changes related to the commodity price effect in the Gulf of America were immaterial.

During the year ended December 31, 2025, we had an overall proved undeveloped reserves decrease of 50.4 MMBoe primarily due to the conversion of proved undeveloped reserves to proved developed reserves during 2025 related to the startup of three wells in Greater Tortue Ahmeyim Phase 1 project (-63.9 MMBoe), the drilling of two wells in Greater Jubilee (-16.7 MMBoe), and and sidetracking a well in Marmalard (-0.3 MMBoe). Changes to the plan of development in Marmalard (-1.4 MMBoe) and loss of Ceiba uneconomic PUD volumes (-1.3 MMBoe) resulted in additional proved undeveloped reserve decreases. The license extension and Petroleum Agreement amendments in Greater Jubilee, facilitating additional field development, and an update to the GSA (+35.6 MMBoe) as well as a positive revision driven by an addition of a sidetrack in Winterfell (+0.6 MMBoe) partially offset the overall decrease in proved undeveloped reserves.

In Ghana, we converted 16.7 MMBoe of proved undeveloped reserves to proved developed with the drilling of two wells in Jubilee at a cost of approximately $61.0 million. 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 in the Greater Tortue Ahmeyim Phase 1 project, 63.9 MMBoe of proved undeveloped reserves were converted to proved developed via three previously drilled wells. In the Gulf of America, we converted 0.3 MMBoe with the sidetracking of a well in Marmalard at a cost of $6.2 million.

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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. Also impacting reserves were negative revisions of 7.5 MMBoe due to field performance primarily related to the J-69 & J-68 wells, partially offset by the positive revision of 5.4 MMBoe due to drilling of two wells that had no prior proved recognition. There were no changes related to the commodity price effect in Jubilee. Changes at TEN include a negative revision of 2.5 MMBoe, primarily driven by removal of future development opportunities from the TEN Fields. The TEN net production for the December 31, 2024 was 1.5 MMBoe, for an overall decrease in reserves of 4.0 MMBoe. We note that the overall gas reserves did not change significantly in TEN and that there were no changes related to the commodity price effect. Changes at Equatorial Guinea included a negative revision of 3.0 MMBoe primarily due to loss of uneconomic PUD volumes in Okume, in addition to the net production of 3.4 MMBoe. The overall net reserves at Equatorial Guinea decreased by 6.4 MMBoe. There were no changes related to the commodity price effect on reserves in Equatorial Guinea. Changes in Mauritania and Senegal include a small positive revision of 0.9 MMBoe due to change in the calculated net reserves amount based on the updated economic parameters as part of the petroleum contract calculations. There were no changes related to the commodity price effect on reserves in Mauritania and Senegal. 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. The Gulf of America net production for the year ended December 31, 2024 was 5.6 MMBoe for an overall reserves decrease of 0.9 MMBoe. The changes related to the commodity price effect in the Gulf of America were immaterial.

During the year ended December 31, 2024, we had an overall proved undeveloped reserves decrease of 18.0 MMBoe primarily due to the conversion of proved undeveloped reserves to proved developed reserves during 2024 related to the drilling of three wells in Jubilee (-16.3 MMBoe), the drilling of two wells in Equatorial Guinea (-1.8 MMBoe), completing two Winterfell wells (-2.9 MMBoe) and the installation of the subsea pump in Odd Job (-1.4 MMBoe). Additionally, we had increases to proved undeveloped reserves during the ended December 31, 2024 including from the optimization of future well forecasts in Jubilee (+7.1 MMBoe), a 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 (+0.9 MMBoe), the addition of two undeveloped wells in Ceiba (+1.3), and the addition of two undeveloped wells in Marmalard (+1.0 MMBoe), offset by the removal of additional planned development in TEN (-3.2 MMBoe) and removal of Okume uneconomic PUD volumes (-2.7 MMBoe).

In Ghana, we converted 16.3 MMBoe 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. In Equatorial Guinea, we converted 1.8 MMBoe of proved undeveloped reserves to proved developed reserves at a cost of $142.6 million by drilling of two wells. In Mauritania and Senegal, we spent approximately $310.9 million progressing the Greater Tortue Ahmeyim Phase 1 project. In the Gulf of America, we converted 1.4 MMBoe at a cost of approximately $42.6 million with the installation of the subsea pump in Odd Job. In addition, we converted 2.9 MMBoe with the completion of two wells in the Winterfell Field at a cost of $78.9 million.

Changes during the year ended December 31, 2023 at Jubilee include a positive revision of 35.1 MMBoe primarily due to positive field performance, the addition of gas sales recognition and positive drilling results, offset by Jubilee net production of 12.8 MMBoe. There were no changes related to the commodity price effect in Jubilee. These revisions resulted in an overall increase of 22.4 MMBoe. Changes at TEN include a negative revision of 12.6 MMBoe, primarily driven by a change in the partnership’s development work scope for the TEN Fields and well performance, net TEN production of 1.3 MMBoe, for an overall decrease in reserves of 13.9 MMBoe. There were no changes related to the commodity price effect in TEN. Changes at Equatorial Guinea included a positive revision of 3.0 MMBoe due to field performance, offset by a negative revision related to the commodity price effect of 0.7 MMBoe and net production of 3.5 MMBoe. The overall net reserves at Equatorial Guinea decreased by 1.1 MMBoe. Changes in Mauritania and Senegal include a small positive revision of 1.3 MMBoe due to optimization of the timing of the Greater Tortue Ahmeyim Phase 1 project. There were no changes related to the commodity price effect on reserves in Mauritania and Senegal. Changes at the Gulf of America include a negative revision of 2.3 MMBoe primarily driven by the performance of Odd Job and Tornado Fields as well as the negative results from the drilling of a Marmalard well. The Gulf of America net production for the year ended December 31, 2023 was 5.6 MMBoe for an overall reserves decrease of 7.9 MMBoe. The changes related to the commodity price effect in the Gulf of America were immaterial.

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

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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). Conversion of proved undeveloped volumes to proved developed related to drilling during 2023 includes the drilling of five wells in Jubilee (-21.5 MMBoe) and one well in Marmalard (-0.8 MMBoe).

In Jubilee, we converted 21.5 MMBoe of proved undeveloped reserves to proved developed with the drilling of five wells at a cost of approximately $98.0 million as well as approximately $91.3 million in subsea costs. In addition, we spent approximately $40.5 million on wells that are expected to convert in future years. In Mauritania and Senegal, we spent approximately $259.8 million progressing the Greater Tortue Ahmeyim Phase 1 development. In the Gulf of America, we converted 0.8 MMBoe at a cost of approximately $16.5 million with the drilling of one well in the Marmalard Field. 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.

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. These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on 12‑month historical unweighted first‑day‑of‑the‑month average prices, rather than year‑end prices. For a definition of proved reserves under the SEC rules, see the “Glossary and Selected Abbreviations.” For more information regarding our independent petroleum engineers, please see “—Independent petroleum engineers” below.

Our estimated proved reserves and related future net revenues, PV‑10 and Standardized Measure were determined in accordance with SEC rules for proved reserves.

Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). 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. 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. 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 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 reports were prepared at our request to estimate our reserves and related future net revenues and PV‑10 for the periods indicated therein. 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. 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. In the process of the reserves evaluation, RSC did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of RSC which brought into question the validity or sufficiency of any such information or data, RSC would not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. 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

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operating conditions, consistent with the definition in Rule 4‑10(a)(2) of Regulation S‑X. 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. The assumptions, data, methods and precedents were appropriate for the purpose served by these reports, and RSC used all methods and procedures as it considered necessary under the circumstances to prepare the report.

Technology used to establish proved reserves

Under the SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have proved effective by actual comparison of production from projects in the same reservoir interval, an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, RSC employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, production and injection data, electrical logs, radioactivity logs, acoustic logs, whole core analysis, sidewall core analysis, downhole pressure and temperature measurements, reservoir fluid samples, geochemical information, geologic maps, seismic data, well test and interference pressure and rate data. Reserves attributable to undeveloped locations were estimated using performance from analogous wells with similar geologic depositional environments, rock quality, appraisal plans and development plans to assess the estimated ultimate recoverable reserves as a function of the original oil in place. These qualitative measures are benchmarked and validated against sound petroleum reservoir engineering principles and equations to estimate the ultimate recoverable reserves volume. These techniques include, but are not limited to, nodal analysis, material balance, and numerical flow simulation.

Internal controls over reserves estimation process

In our Reservoir Engineering team, we maintain an internal staff of petroleum engineering and geoscience professionals with significant experience that contribute to our internal reserve and resource estimates. This team works closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of data furnished in their reserve and resource estimation process. 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. 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. 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.

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. He graduated from University of California at Berkeley in 2000 with Bachelor of Science Degrees in Chemical Engineering and Material Science Engineering, and he received a Master of Science degree in Petroleum Engineering from University of Southern California in 2007. Mr. Famurewa meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

The Audit Committee provides oversight on the processes utilized in the development of our internal reserve and resource estimates and meets with the senior RSC representative outside the presence of any Company representatives on an annual basis to discuss RSC’s reserve assessment process in the preparation of their reserves estimates. In addition, our Reservoir Engineering team meets with representatives of our independent petroleum engineers to review our assets and discuss

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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.

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.

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(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. Our net acreage in Ghana may be affected by any redetermination of interests in the Jubilee Unit. Additionally, the Ghana partnership received Government approval in December 2025 for the license extension for its WCTP and DT Petroleum Agreements, which cover the Jubilee and TEN fields, to 2040. As part of the extensions, 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. Our net acreage in Mauritania and Senegal may be affected by any redetermination of interests in the Greater Tortue Ahmeyim Unit.

(2)The Exploration Period of the WCTP petroleum contract and DT petroleum contract has expired. The undeveloped area reflected in the table above represents acreage within our discovery areas that were not subject to relinquishment on the expiry of the Exploration Period.

(3)Our developed 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. For undeveloped areas, the licenses are immaterial with various exploration phases, with all ending by 2034.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including wells awaiting connections. For wells that produce both oil and gas, the well is classified as an oil well. The following table sets forth the number of productive oil and gas wells in which we held an interest at December 31, 2025:

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(1)Of the 164 productive wells, 47 (gross) or 16 (net) have multiple completions within the wellbore.

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(2)Table above reflects our additional interests acquired in Ghana and Gulf of America. In Ghana, the partnership received Government approval in December 2025 for the license extension for its WCTP and DT Petroleum Agreements, which cover the Jubilee and TEN fields, to 2040. As part of the extensions, 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.

Drilling activity

The results of oil and natural gas wells drilled and completed for each of the last three years were as follows:

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(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. 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.

(2)A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled.

(3)A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be a productive well, as opposed to the year the well was drilled.

(4)Includes the Winterfell-4 well which is considered a step out well from an accounting perspective, but was drilled as part of the Winterfell phased development.

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The following table shows the number of wells that are in the process of being drilled or are in active completion stages, and the number of wells suspended or waiting on completion as of December 31, 2025.

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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. In addition, in connection with the approval of the Jubilee Phase 1 PoD, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to GNPC at no cost. As of January 1, 2023, the Jubilee partners had fulfilled this commitment. 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 December 2025, as part of the extension of the WCTP and DT Petroleum Agreements, the Ghana partners and Government of Ghana have approved an amended gas sales agreement at a price of $2.50 per MMBtu through the extended expiration date of 2040 for the WCTP and DT licenses.

Sales and Marketing

As provided under the Jubilee UUOA and the WCTP and DT petroleum contracts, we are entitled to lift and sell our share of the Jubilee and TEN production as are the other Jubilee Unit and TEN partners. 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. In December 2025, the Ghana partners and Government of Ghana have approved an amended gas sales agreement at a price of $2.50 per MMBtu through the extended expiration date of 2040 for the WCTP and DT licenses. A gas pipeline from the Jubilee Field transports such natural gas onshore for processing and sale. In Equatorial Guinea, as provided under the petroleum contract for Block G, we are entitled to lift and sell our share of the Ceiba Field and Okume Complex production as are the other Block G partners. 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. Currently, Kosmos sells GoA oil production exclusively to a single buyer on a multi-year term deal. GoA crude oil sales take place monthly 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. We actively market our crude oil and natural gas to purchasers, and sales prices for purchased oil and natural gas volumes are negotiated with purchasers and are based on certain published indices. We sell the NGLs entrained in the natural gas that we produce. The arrangements to sell these products first require natural gas to be processed at an onshore gas processing plant. Once the liquids are removed and fractionated (separated into the individual hydrocarbon chains for sale), the products are sold by the processing plant. 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

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on what the processing plant can receive from a third-party purchaser. The gas processing and subsequent sales of NGLs are subject to contracts with longer terms and dedications of life of lease production from the Company’s leases offshore.

In Mauritania and Senegal, we sell our entitlement share of LNG production from the Greater Tortue Ahmeyim Field free on board (FOB) under the Tortue Phase 1 SPA with BPGM which was signed in February 2020. The annual contract quantity under the Tortue Phase 1 SPA is 127,951,000 MMBtu (the “ACQ”) which is equivalent to approximately 2.45 million tonnes per annum, subject to limited downward adjustment by the sellers. 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. As provided under the GTA UUOA and the C8 and Saint-Louis Offshore Profond petroleum contracts, we are entitled to lift and sell our share of condensate production from the Greater Tortue Ahmeyim Field. Condensate cargos are typically sold to purchasers with the sale taking place offshore Mauritania and Senegal on the spot market. LNG volumes in excess of the annual contract quantity of 2.45 mtpa associated with existing infrastructure are also sold to BPGM.

There are a variety of factors which affect the market for oil, including the proximity and capacity of transportation facilities, demand for oil both within the local market and beyond, the marketing of competitive fuels and the effects of government regulations on oil production and sales. Our revenue can be materially affected by current economic conditions and the price of oil. However, based on the current demand for crude oil and the fact that alternative purchasers are available, we believe that the loss of one of our marketing agents and/or any of the purchasers identified by our marketing agent would not have a long‑term material adverse effect on our financial position or results of operations. 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. Any potential disruption will depend on the duration and intensity of these events, which are highly uncertain and cannot be predicted at this time.

Competition

The oil and gas industry is competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring licenses and leases. 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. Furthermore, these companies may also be better able to withstand the financial pressures of lower commodity prices, unsuccessful wells, volatility in financial markets and generally adverse global and industry‑wide economic conditions. These companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position.

Historically, we have also been affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews. Shortages of, or increasing costs for, experienced drilling crews and equipment and services may restrict our ability to drill wells and conduct our operations.

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. 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. 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. Our licenses and leases are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of, or affect the carrying value of, our interests.

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Environmental Matters

General

We are subject to various stringent and complex international, foreign, federal, state and local environmental, health and safety laws and regulations governing matters including the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use and transportation of regulated materials; and the health and safety of our employees. These laws and regulations may, among other things:

•require the acquisition, renewal and maintenance of various permits before operations commence or for operations to continue;

•enjoin operations or facilities to comply with applicable regulations and permits;

•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

•limit, cap, tax or otherwise restrict emissions of GHG and other air pollutants or otherwise seek to address or minimize the effects of climate change, as well as require disclosure of GHG emissions and other climate change-related information;

•limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and

•require measures to mitigate or remediate pollution, including pollution resulting from our block partners’ or our contractors’ operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Compliance with these laws can be costly; the regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. We are committed to continued compliance with all environmental laws and regulations applicable to our operations in all countries in which we do business. We have established policies, operating procedures and training programs designed to limit the environmental impact of our operations and to identify and comply with existing and new laws and regulations, however the cost of compliance with existing or more stringent laws and regulations in the future could have a material adverse effect on our financial condition and results of operations.

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. Our operations could be adversely affected to the extent laws or regulations are enacted or other governmental action is taken that prohibits or restricts offshore drilling or imposes environmental requirements that increase costs to the oil and gas industry in general, such as more stringent or costly waste handling, disposal or cleanup requirements or financial responsibility and assurance requirements.

Per common industry practice, under agreements governing the terms of use of the drilling rigs contracted by us or our block or lease partners, the drilling rig contractors typically indemnify us and our block partners in respect of pollution and environmental damage originating above the surface of the water and from such drilling rig contractor’s property, including their drilling rig and other related equipment. Furthermore, pursuant to the terms of the operating agreements for our blocks and leases, except in certain circumstances, each block or lease partner is responsible for its share of liabilities in proportion to its participating interest incurred as a result of pollution and environmental damage, containment and clean‑up activities, loss or damage to any well, loss of oil or natural gas resulting from a blowout, crater, fire, or uncontrolled well, loss of stored oil and natural gas, as well as for plugging or bringing under control any well. 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. We believe our insurance is carried in amounts typical for the industry relative to our size and operations and in accordance with our contractual and regulatory obligations.

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International (Non-operated)

Tullow, BP, and Trident, our partners and the operators, respectively, of (i) the Jubilee Unit and the TEN Fields offshore Ghana, (ii) the Greater Tortue Ahmeyim Field offshore Mauritania and Senegal, and (iii) the Ceiba Field and Okume Complex offshore Equatorial Guinea, respectively, maintain Oil Spill Response Plans (“OSRP”) covering the joint operations. The OSRPs include access to Oil Spill Response Limited’s (“OSRL”) oil spill response services comprising technical expertise and assistance, including access to response equipment and dispersant spraying systems. The equipment includes capping stacks, debris removal, subsea dispersant and auxiliary equipment. The equipment meets industry accepted standards and can be deployed by air cargo and other conventional means to suit multiple application scenarios. Under the OSRPs, emergency response teams may be activated to respond to oil spill incidents.

In addition, Kosmos develops an emergency response plan and subscribes to a response organization to prepare and demonstrate our readiness to respond to a subsea well control incident in the event we are the operator.

Gulf of America (Operated and Non-operated)

After the major well control incident and oil release in the Gulf of America in 2010, the U.S. Department of Interior updated regulations which govern the type, amount and capabilities of response equipment that needs to be available to operators to respond to similar incidents. These regulations also dictate the type and frequency of training that operating personnel need to receive and demonstrate proficiency in. Kosmos also has an OSRP which is approved by the Bureau of Safety and Environmental Enforcement (“BSEE”). This OSRP would be activated if needed in the event of an oil spill or containment event in the Gulf of America where Kosmos is the operator. Kosmos joined several cooperatives that were established to meet the requirements of the new regulations. For capping and containment, Kosmos joined the HWCG, LLC consortium whose capabilities include; (i) one dual ram capping stack rated to 15,000 psi and one valve capping stack rated to 20,000 psi, (ii) intervention equipment to cap and contain a well with the mechanical and structural integrity to be shut in at water depths up to 10,000 feet, and (iii) the ability to capture and process 130,000 barrels of fluid per day and 220 MMcf of gas per day. Kosmos is also a member of the Clean Gulf Associates (“CGA”) Oil Spill Cooperative, which provides oil spill response capabilities to meet regulatory requirements. Equipment and services include a High Volume Open Sea Skimming System (“HOSS”), dedicated oil spill response vessels strategically positioned along the U.S. gulf coast, dispersants and dispersant delivery systems, various types of spill response booms and mobile wildlife rehabilitation equipment. Due to federal regulations, all of the HWCG and CGA equipment is dedicated to U.S. operations and cannot be utilized outside the country. In addition, Kosmos is also a member of the Marine Spill Response Corporation (“MSRC”) which also provides various oil spill response services for coastal and inland environments in the Gulf of America.

Cybersecurity

At Kosmos Energy, cybersecurity risk management is an integral part of our overall Information Technology Disaster Recovery and Security Incident Response Plan. Our cybersecurity risk management program is designed to align with our business strategy based on the size of our company and the level of complexity of our information technology systems and industry best practices. The framework for handling cybersecurity threats and incidents including threats and incidents associated with the use of applications developed and services provided by third-party service providers and coordination across different departments of our company includes assessing the severity of a cybersecurity threat associated with a third-party service provider, various cybersecurity countermeasures and mitigation strategies and informing management and the Audit Committee to our board of directors of material cybersecurity threats and incidents. Our information technology team is responsible for assessing our cybersecurity risk management program and we currently do not engage third parties for such design of our cybersecurity risk management program. In addition, our information technology team provides cybersecurity training to all employees and contractors annually.

The Audit Committee to our board of directors has overall oversight responsibility for our risk management, and is charged with oversight of our cybersecurity risk management program. The Audit Committee is responsible for ensuring that management has processes in place designed to identify and evaluate cybersecurity risks to which the company is exposed and implement processes and programs to manage cybersecurity risks and mitigate cybersecurity incidents. The Audit Committee also reports material cybersecurity risks to our full board of directors. 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. Our Senior Director of Information Technology (IT), the technical lead of our IT department, reports directly to the Vice President of Administration. Our Vice President of Administration and our Senior Director of IT receive reports from our information technology team and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents. Our IT leadership and dedicated personnel are

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certified and experienced information systems security professionals and information security managers with many years of experience. 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.

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. For more information about these risks, please see “Risk Factors” in this annual report on Form 10-K.

Human Capital Resources

Health and Safety

The health and safety of our employees and those that work with us is a priority for Kosmos. Employees and contractors are expected to take all necessary and reasonable actions to ensure safe operations by following safe work practices, complying with relevant policies and regulations, and completing all applicable training. To support our dedication to health, safety and the environment, we have a comprehensive Health, Safety, Environment and Security (“HSES”) management system that applies to all Kosmos employees and contractors known as “The Standard.” In addition to adoption of The Standard, Kosmos fosters a strong safety culture through online and in person training, regular emergency response drills, and impactful safety discussions.

Culture, Engagement and Development

Kosmos aims to be a world-class company known for delivering results and being a workplace of choice. We pride ourselves on our ability to provide employees with careers that are professionally challenging, personally rewarding, and focused on delivering value. We aim to provide a stimulating and rewarding work environment through an inclusive culture that promotes entrepreneurial thinking, facilitates teamwork, and embraces ethical behavior.

Kosmos is committed to investing in the development of our employees. We support development through a blend of learning approaches including in-person and virtual training opportunities, on-the-job training, conferences, cross team projects and experiences and our leadership development program. Each year, all employees also have an opportunity to provide feedback on the employee experience and Kosmos culture through our annual employee opinion survey. 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.

Diversity and Inclusion

Kosmos focuses on recruiting, retaining, and developing a diverse and inclusive workforce that embraces our values and culture. We seek to promote diversity in our workforce both because it is the right thing to do and because it gives us access to the widest range of talents. Through social and educational events that address the different backgrounds and identities of employees, Kosmos helps foster a spirit of inclusion across the company. We promote and celebrate the array of diverse perspectives and experiences of Kosmos employees and applicants, whether in terms of race, ethnicity, sex, gender, sexual orientation, gender expression, religion, national origin, disability, or experiences.

We seek to employ qualified individuals from the countries in which we operate and are proud of our record of recruitment and retention of local staff. This year we maintained 100% local employees across all our host country offices.

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. All domestic employees are awarded equity in the company as part of the total reward package,

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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.

These benefits are intended to both promote the long-term emotional, physical, and financial health and well-being of our employees and increase employee engagement and retention. Additionally, we believe that these benefits help facilitate a strong work-life balance and a culture that prioritizes overall employee wellness.

Corporate Information

In December 2018, Kosmos Energy Ltd. changed our jurisdiction of incorporation from Bermuda to the State of Delaware, USA. We maintain a registered office in Delaware at Corporation Trust Center, 1209 Orange Street, Wilmington, Delaware 19801. Our executive offices are maintained at 8176 Park Lane, Suite 500, Dallas, Texas 75231, and its telephone number is +1 (214) 445 9600.

Available Information

Kosmos is listed on the NYSE and LSE and our common stock is traded under the symbol KOS. We file or furnish annual, quarterly and current reports, proxy statements and other information with the SEC as well as the London Stock Exchange's Regulatory News Service (“LSE RNS”). The SEC maintains a website at http://www.sec.gov that contains documents we file electronically with the SEC. The LSE RNS maintains a website at http://www.londonstockexchange.com that contains documents we file electronically with the LSE RNS.

The Company also maintains an internet website under the name www.kosmosenergy.com. The information on our website is not incorporated by reference into this annual report on Form 10‑K and should not be considered a part of this annual report on Form 10‑K. Our website is included as an inactive technical reference only. We make available, free of charge, on our website, our annual report on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC.