KOS Kosmos Energy Ltd. - 10-K

Item 1A.  Risk Factors

You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this report, including the consolidated financial statements and the related notes included in “Item 8. Financial Statements and Supplementary Data.” If any of the following risks actually occurs, our business, business prospects, financial condition, results of operations or cash flows could be materially adversely affected. The risks below are not the only ones we face. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us.

Summary Risk Factors

Our business is subject to a number of risks, including risks that may prevent us from achieving our business objectives or may adversely affect our business, financial condition, results of operations, cash flows, and prospects. These risks are discussed more fully below and include, but are not limited to, risks related to:

Our Oil and Natural Gas Operations

• We have limited proved reserves;

• We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects;

• Drilling wells is speculative and may not result in any discoveries;

• Development wells may not result in commercially productive quantities of oil and gas reserves;

• Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties;

• We are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights;

• Inability of third parties who contract with us to meet their obligations may adversely affect our financial results;

• The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination;

• We are not the operator on all of our license areas and facilities and do not hold all of the working interests in certain of our license areas;

• Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate;

• The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and gas reserves;

• We may not be able to commercialize our interests in some of the natural gas produced from our license areas;

• Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production;

• We are subject to numerous risks inherent to the exploration, development, and production of oil and natural gas;

• We are subject to drilling and other operational and environmental risks and hazards;

• Our operations may be materially adversely affected by weather-related events, including, but not limited to, tropical storms and hurricanes, and the physical effects of climate change;

• The development schedule of oil and natural gas projects is subject to delays and cost overruns;

• Our offshore and deepwater operations involve special risks that could adversely affect our results of operations;

• We have had, and may in the future have, disagreements with certain host governments and contractual counterparties regarding certain of our rights and responsibilities;

• The geographic locations of our licenses in Africa and the Gulf of America subject us to a risk of loss of revenue or curtailment of production from factors specifically affecting those areas;

Our Business and Financial Condition

• A substantial or extended decline in oil, natural gas and LNG prices may adversely affect our business, financial condition and results of operations;

• Our business plan requires substantial additional capital;

• We may be required to take write‑downs of the carrying values of our oil and natural gas assets due to decreases in the estimated future net cash flows from our operations, which may occur as a result of decreases in oil, natural gas, and LNG prices, poor field performance, increased expenditures or changes in the timing or amount of investment, among other things, and such decreases could result in reduced availability under our commercial debt facility;

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• We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration, development, and production activities and ESG considerations including climate change and the transition to a lower carbon economy;

• Outbreaks of disease may adversely affect our business operations and financial condition;

• Deterioration in the credit or equity markets could adversely affect us;

• We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage;

• Slower global economic growth rates may materially adversely impact our operating results and financial position;

• Increased costs and availability of capital could adversely affect our business;

• Our derivative activities could result in financial losses or could reduce our income;

• Our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions;

• Provisions of our Senior Notes and Convertible Senior Notes could discourage an acquisition of us by a third-party;

• Our level of indebtedness may increase and thereby reduce our financial flexibility;

• We are a holding company and our ability to make payments on our outstanding indebtedness is dependent upon the receipt of funds from our subsidiaries;

• We may be subject to risks in connection with acquisitions and the integration of acquisitions may be difficult;

• If we fail to realize the anticipated benefits of acquisitions, our results of operations may be adversely affected;

• A cybersecurity incident, including a breach of digital security, could result in information theft, data corruption, operational disruption, and/or financial loss;

• We are incorporating artificial intelligence technologies into our processes and these technologies may present business, operational, compliance, cybersecurity, and reputational risks;

• Our ability to utilize net operating loss carryforwards may be subject to certain limitations;

Regulation

• Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic, and environmental circumstances;

• More comprehensive and stringent regulation in the Gulf of America has materially increased costs and delays in offshore oil and natural gas exploration and production operations;

• The oil and gas industry is intensely competitive and many of our competitors possess and employ substantially greater resources than us;

• Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business;

• We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs;

• We may be exposed to assertions concerning or liabilities under anti‑corruption laws;

• Federal regulatory law could have an adverse effect on our ability to use derivative instruments;

General Matters

• We are dependent on certain members of our management and technical team;

• We operate in a litigious environment;

• We face various risks associated with global activism;

• Our share price may be volatile, and purchasers of our common stock could incur substantial losses; and

• Holders of our common stock will be diluted if additional shares are issued.

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Risks Relating to our Oil and Natural Gas Operations

We have limited proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.

We have limited proved reserves. A portion of our oil and natural gas assets consists of discoveries without approved PoDs and with limited well penetrations, as well as identified yet unproven prospects based on available seismic and geological information that indicates the potential presence of hydrocarbons. However, the areas we decide to drill may not yield oil or natural gas in commercial quantities or quality, or at all. Many of our current discoveries and all of our prospects are in various stages of evaluation that will require substantial additional analysis and interpretation. Even when properly used and interpreted, 2D, 3D and 4D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. Accordingly, we do not know if any of our discoveries or prospects will contain oil or natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil or natural gas is found on our discoveries or prospects in commercial quantities, construction costs of gathering lines, subsea infrastructure, other production facilities and floating production systems and transportation costs may prevent such discoveries or prospects from being economically viable, and approval of PoDs by various regulatory authorities, a necessary step in order to develop a commercial discovery, may not be forthcoming. Additionally, the analogies drawn by us using available data from other wells, more fully explored discoveries or producing fields may not prove valid with respect to our drilling prospects. We may terminate our drilling program for a discovery or prospect if data, information, studies and previous reports indicate that the possible development of a discovery or prospect is not commercially viable and, therefore, does not merit further investment. If a significant number of our discoveries or prospects do not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.

The deepwater offshore Mauritania and Senegal, an area in which we currently focus a substantial amount of our development efforts, has only recently been considered economically viable for hydrocarbon production due to the costs and difficulties involved in drilling and development at such depths and the relatively recent discovery of commercial quantities of hydrocarbons in the region. We have limited proved reserves, and we may not be successful in developing additional commercially viable production from our other discoveries and prospects.

We face substantial uncertainties in estimating the characteristics of our discoveries and our prospects.

We report numerical and other measures of the characteristics of our discoveries and prospects. These measures may be incorrect, as the accuracy of these measures is a function of available data, geological interpretation and judgment. To date, a limited number of our prospects have been drilled. Any analogies drawn by us from other wells, discoveries or producing fields may not prove to be accurate indicators of the success of developing proved reserves from our discoveries and prospects. Furthermore, we have no way of evaluating the accuracy of the data from analog wells or prospects produced by other parties which we may use.

It is possible that few or none of our wells to be drilled will find accumulations of hydrocarbons in commercial quality or quantity. Any significant variance between actual results and our assumptions could materially affect the quantities of hydrocarbons attributable to any particular prospect.

Drilling wells is speculative, often involving significant costs that may be more than we estimate, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

Exploring for and developing hydrocarbon reserves involves a high degree of technical, operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to rising inflationary pressure, a tightening in the supply of various types of oilfield equipment and related services or unanticipated geologic conditions or operational challenges.

Before a well is spud, we incur significant geological and geophysical (seismic) costs, which are incurred whether or not a well eventually produces commercial quantities of hydrocarbons or is drilled at all. Drilling may be unsuccessful for many reasons, including geologic conditions, weather, cost overruns, equipment shortages and mechanical difficulties or force majeure events. Exploratory wells bear a much greater risk of failure than development wells. In the past we have experienced

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unsuccessful drilling efforts, having drilled dry holes. Furthermore, the successful drilling of a well does not necessarily result in the commercially viable development of a field or be indicative of the potential for the development of a commercially viable field. A variety of factors, including geologic and market‑related, can cause a field to become uneconomic or only marginally economic. A lack of drilling opportunities or projects that cease production may cause us to incur significant costs associated with an idle rig and/or related services, particularly if we cannot contract out rig slots to other parties. Many of our prospects that may be developed require significant additional exploration, appraisal and development, regulatory approval and commitments of resources prior to commercial development. In addition, a successful discovery would require significant capital expenditure in order to appraise, develop and produce oil and natural gas, even if we deemed such discovery to be commercially viable. See “—Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.” In the international areas in which we operate, we face higher above‑ground risks necessitating higher expected returns, the requirement for increased capital expenditures due to a general lack of infrastructure and underdeveloped oil and gas industries, and increased transportation expenses due to geographic remoteness, which either require a single well to be exceptionally productive, or the existence of multiple successful wells, to allow for the development of a commercially viable field. See “—Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic, and environmental circumstances, and changes in laws and regulations, in the countries and regions in which we operate.” Furthermore, if our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and could be forced to modify our plan of operation.

Development drilling may not result in commercially productive quantities of oil and gas reserves.

Our exploration success has provided us with major development and appraisal projects on which we are moving forward, and any future exploration discoveries will also require significant development efforts to bring to production. We must successfully execute our development projects, including development drilling, in order to generate future production and cash flow. However, development drilling is not always successful and the profitability of development projects may change over time.

For example, in new development projects available data may not allow us to completely know the extent of the reservoir or choose the best locations for drilling development wells. A development well we drill may be a dry hole or result in noncommercial quantities of hydrocarbons. All costs of development drilling and other development activities are capitalized, even if the activities do not result in commercially productive quantities of hydrocarbon reserves. This puts a property at higher risk for future impairment if commodity prices significantly decrease, operating or development costs significantly increase or reservoir performance is below expectations.

Our identified drilling and infrastructure locations are scheduled out over time, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling or infrastructure installation or modification.

Our management team has identified and scheduled drilling locations and possible infrastructure locations on our license and lease areas over a multi‑year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by block or lease partners and national and state regulators, seasonal conditions, oil prices, assessment of risks, costs and drilling results. For example, a shutdown of the U.S. federal government could delay the regulatory review and approval process associated with drilling or developmental activities within our license areas in the Gulf of America. The final determination on whether to drill or develop any of these locations will be dependent upon the factors described elsewhere in this report as well as, to some degree, the results of our drilling and production activities with respect to our established wells and drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled or infrastructure installed or modified within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. As such, our actual drilling and development activities may be materially different from our current expectations, which could adversely affect our results of operations and financial condition.

Under the terms of certain of our petroleum contracts, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to drill these wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects or undeveloped discoveries.

In order to protect our exploration and production rights in our license areas, we may be required to meet various drilling and declaration requirements. In general, unless we make and declare discoveries within certain time periods specified in certain of our petroleum contracts and licenses, our interests in the undeveloped parts of our license areas may lapse. Should

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the prospects yield discoveries, we cannot assure you that we will not face delays in the appraisal and development of these prospects or otherwise have to relinquish these prospects. The costs to maintain petroleum contracts over such areas may fluctuate and may increase significantly since the original term, and we may not be able to renew or extend such petroleum contracts on commercially reasonable terms or at all. Our actual drilling activities may therefore materially differ from our current expectations, which could adversely affect our business.

Under certain petroleum contracts, we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the licenses. As of December 31, 2025, we have a commitment to one development well in Equatorial Guinea. Additionally, as part of the recent extension of the Petroleum Agreements covering the Jubilee and TEN fields, the Jubilee plan of development is amended to include up to twenty additional wells in the field, with a commitment to drill a minimum of ten additional wells. In certain other petroleum contracts, we are in the initial exploration phases, some of which have certain obligations that have yet to be fulfilled. Over the course of the next several years, we may choose to enter into the next phase of those petroleum contracts which will likely include firm obligations to drill wells. Failure to execute our obligations may result in our loss of the licenses.

The exploration period of some of our petroleum contracts has expired or may expire in the near future. For each of our petroleum contracts, we cannot assure you that any renewals or extensions will be granted or whether any new agreements will be available on commercially reasonable terms, or, in some cases, at all. For additional detail regarding the status of our operations with respect to our various petroleum contracts, please see “Item 1. Business—Operations by Geographic Area.”

The inability of one or more third parties who contract with us to meet their obligations to us may adversely affect our financial results.

We may be liable for certain costs if third parties who contract with us or with the operators of our license and lease areas are unable to meet their commitments under such agreements. We are currently exposed to credit risk through joint interest receivables from our block and/or unit partners. If any of our partners in the blocks or units in which we hold interests are unable to fund their share of the exploration, development and decommissioning expenses, we may be liable for such costs. In the past, certain of our partners have not paid their share of block costs in the time frame required by the relevant agreements for these blocks. This has resulted in such party being in default, which in return requires Kosmos and its non‑defaulting block partners to pay their proportionate share of the defaulting party’s costs during the default period. Should a default not be cured, Kosmos could be required to pay its share of the defaulting party’s costs going forward.

In addition, we and the operators of our license and lease areas contract with third parties to conduct drilling and related services on our development projects and exploration prospects. Such third parties may not perform the services they provide us on schedule or within budget. Furthermore, the drilling equipment, facilities and infrastructure owned and operated by such third parties is highly complex and subject to malfunction and breakdown. Any malfunctions or breakdowns may be outside our control and result in delays, which could be substantial. Any delays in our drilling campaign caused by equipment, facility or equipment malfunction or breakdown could materially increase our costs of drilling and cause an adverse effect on our business, financial position and results of operations.

Our principal exposure to credit risk will be through receivables resulting from the sale of our oil, natural gas and LNG as well as our commodity derivatives contracts. The inability or failure of our significant customers or counterparties to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. We have joint interest receivables, domestic gas payment receivables, and project development carries in Ghana, Mauritania and Senegal, and our counterparties under these agreements may have difficulty in paying amounts due to Kosmos. The inability or failure of third parties we contract with to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We are unable to predict sudden changes in creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited and we could incur significant financial losses.

The unit partners’ respective interests in the Jubilee Unit and Greater Tortue Ahmeyim Unit are subject to redetermination and our interests in each such unit may decrease as a result.

The interests in and development of the Jubilee Field are governed by the terms of the Jubilee UUOA. The parties to the Jubilee UUOA, the collective interest holders in each of the WCTP and DT Blocks, initially agreed that interests in the Jubilee Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests in the Jubilee Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the Jubilee UUOA, the percentage of such contributed interests is subject to a process of redetermination. Following an initial redetermination process completed on October 14, 2011, the tract participation was determined to be 54.4%

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for the WCTP Block and 45.6% for the DT Block. Consequently, our Unit Interest (participating interest in the Jubilee Unit) was increased from 23.5% to 24.1% upon completion of the initial redetermination process. Following the acquisition of Anadarko WCTP Company in October 2021 and completion of the subsequent pre-emption by Tullow in March of 2022, Kosmos’ interest in the Jubilee Unit Area now stands at 38.6%. An additional redetermination could occur sometime if requested by a party that holds greater than a 10% interest in the Jubilee Unit. We cannot assure you that any redetermination pursuant to the terms of the Jubilee UUOA will not negatively affect our interests in the Jubilee Unit or that such redetermination will be satisfactorily resolved.

The interests in and development of the Greater Tortue Ahmeyim Field are governed by the terms of the GTA UUOA. The parties to the GTA UUOA, the collective interest holders in each of the Mauritania Block C8 and Senegal Saint Louis Offshore Profond blocks, initially agreed that interests in the Greater Tortue Ahmeyim Unit will be shared equally, with each block deemed to contribute 50% of the area of such unit. The respective interests in the Greater Tortue Ahmeyim Unit were therefore initially determined by the respective interests in such contributed block interests. Pursuant to the terms of the GTA UUOA, the percentage of such contributed interests is subject to a process of redetermination once sufficient development work has been completed in the unit. We cannot assure you that any redetermination pursuant to the terms of the GTA UUOA will not negatively affect our interests in the Greater Tortue Ahmeyim Unit or that such redetermination will be satisfactorily resolved.

We are not, and may not be in the future, the operator on all of our license areas and facilities and do not, and may not in the future, hold all of the working interests in certain of our license areas. Therefore, we have reduced control over the timing of exploration or development efforts, associated costs, and the rate of production of any non‑operated and to an extent, any non‑wholly-owned, assets.

As we carry out our exploration and development programs, we have arrangements with respect to existing license areas and may have agreements with respect to future license areas that result in a greater proportion of our license areas being operated by others. Currently, we are not the operator of the Jubilee Unit, the TEN Fields, the Ceiba Field and Okume Complex, the Greater Tortue Ahmeyim Unit or certain producing fields in the Gulf of America and do not hold operatorship in certain other offshore blocks. As a result, we may have limited ability to exercise influence over the operations of the discoveries or prospects operated by our block or unit partners, or which are not wholly-owned by us, as the case may be. Dependence on block or unit partners could prevent us from realizing our target returns for those discoveries or prospects. Further, because we do not have majority ownership in all of our properties, we may not be able to control the timing, or the scope, of exploration or development activities or the amount of capital expenditures and, therefore, may not be able to carry out one of our key business strategies of minimizing the cycle time between discovery and initial production. The success and timing of exploration and development activities will depend on a number of factors that will be largely outside of our control, including:

• the timing and amount of capital expenditures;

• if the activity is operated by one of our block partners, the operator’s expertise and financial resources;

• approval of other block partners in drilling wells;

• the scheduling, pre‑design, planning, design and approvals of activities and processes;

• selection of technology;

• the available capacity of processing facilities and related pipelines; and

• the rate of production of reserves, if any.

This limited ability to exercise control over the operations on our license areas may cause a material adverse effect on our financial condition and results of operations.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and gas reserves is technically complex. It requires interpretations of available technical data and many assumptions, including those relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value

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of reserves shown in this report. See “Item 1. Business—Our Reserves” for information about our estimated oil and gas reserves and the present value of our net revenues at a 10% discount rate (“PV‑10”) and Standardized Measure of discounted future net revenues (as defined herein) as of December 31, 2025.

In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The process also requires economic assumptions about matters such as oil, natural gas and LNG prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil, natural gas and LNG prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil, natural gas and LNG prices and other factors, many of which are beyond our control.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and gas reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and gas reserves. In accordance with the SEC requirements, we have based the estimated discounted future net revenues from our proved reserves on the 12‑month unweighted arithmetic average of the first‑day‑of‑the‑month price for the preceding twelve months, adjusted for an anticipated market premium, without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas assets will be affected by factors such as:

• actual prices we receive for oil, natural gas and LNG;

• actual cost of development and production expenditures;

• derivative transactions;

• the amount and timing of actual production; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas assets will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this report. Oil prices have recently experienced significant volatility. See “Item 1. Business—Our Reserves.”

We may not be able to commercialize our interests in some of the natural gas produced from our license areas.

The development of the market for natural gas in certain of our international license areas is still in its early stages. Currently the infrastructure to transport and process natural gas on commercial terms is limited and the expenses associated with constructing such infrastructure ourselves may not be commercially viable given local prices currently paid for natural gas. Accordingly, there may be limited or no value derived from the natural gas produced from some of our international license areas.

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. During 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas to the Government of Ghana through May 2024. This interim gas sales agreement was subsequently extended to November 2025 at a price of approximately $3.00 per MMBtu. 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 export associated natural gas from the Jubilee Field could eventually impact our oil production and could cause us to re-inject or flare any natural gas we cannot export.

In Mauritania and Senegal, while we currently only export our gas resource to the LNG market, we also intend to utilize existing facilities for domestic gas delivery. This plan is contingent signing gas sales agreements for domestic gas and

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the necessary infrastructure to transport the gas to domestic onshore markets being constructed. Additionally, such plans are contingent upon receipt of required partner and government approvals.

Our inability to access appropriate equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets or delay our oil and natural gas production.

Our ability to market our oil and natural gas production depends substantially on the availability and capacity of processing facilities, oil and LNG tankers and other infrastructure, including FPSOs, owned and operated by third parties. Our failure to obtain such facilities on acceptable terms could materially harm our business. We also rely on continued access to drilling rigs and construction vessels suitable for the environment in which we operate and on operating infrastructure that allows us to commercially process and market our products. The delivery of drilling rigs or construction vessels may be delayed or cancelled, and we may not be able to gain continued access to suitable rigs, vessels or other operating infrastructure in the future. We may be required to shut in oil and natural gas wells because of the absence of a market or because access to processing facilities may be limited or unavailable. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver the production to market, which could cause a material adverse effect on our financial condition and results of operations. In addition, the shutting in of wells can lead to mechanical problems upon bringing the production back online, potentially resulting in decreased production and increased remediation costs.

We are subject to numerous risks inherent to the exploration and production of oil and natural gas.

Oil and natural gas exploration and production activities involve many risks that a combination of experience, knowledge and interpretation may not be able to overcome. Our future will depend on the success of our exploration and production activities and on the development of infrastructure that will allow us to take advantage of our discoveries. Additionally, many of our license areas are located in deepwater, which generally increases the capital and operating costs, chances of delay, planning time, technical challenges and risks associated with oil and natural gas exploration and production activities. See “— Our offshore and deepwater operations involve special risks that could adversely affect our results of operation.” As a result, our oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore or develop discoveries, prospects or licenses will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

Furthermore, the marketability of expected oil, natural gas, and LNG production from our discoveries and prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of prices (such as recent significant variations in oil, natural gas, and LNG prices), proximity, capacity and availability of drilling rigs and related equipment, qualified personnel and support vessels, processing facilities, transportation vehicles and pipelines, equipment availability, access to markets and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, domestic supply requirements, importing and exporting of oil, natural gas, and LNG, the ability to flare or vent natural gas, health and safety matters, environmental protection and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

In the event that our currently undeveloped discoveries and prospects are developed and become operational, they may not produce oil and natural gas in commercial quantities or at the costs anticipated, and our projects may cease production, in part or entirely, in certain circumstances. Discoveries may become uneconomic as a result of an increase in operating costs to produce oil and natural gas, among other factors. Our actual operating costs and rates of production may differ materially from our current estimates. Moreover, it is possible that other developments, such as increasingly strict environmental, climate change, and health and safety laws, regulations and executive orders and enforcement policies thereunder and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities, delays, an inability to complete the development of our discoveries or the abandonment of such discoveries, which could cause a material adverse effect on our financial condition and results of operations.

We are subject to drilling and other operational and environmental risks and hazards.

The oil and natural gas business involves a variety of risks, including, but not limited to:

• fires, blowouts, spills, cratering and explosions;

• mechanical and equipment problems, including unforeseen engineering complications;

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• uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials;

• gas flaring operations;

• marine hazards with respect to offshore operations;

• formations with abnormal pressures;

• pollution, environmental risks, and geological problems; and

• weather conditions and natural or man‑made disasters.

These risks are particularly acute in deepwater drilling, exploration, and development. Any of these events could result in loss of human life, significant damage to property, environmental or natural resource damage, impairment, delay or cessation of our operations, lower production rates, adverse publicity, substantial losses and civil or criminal liability. We expect to maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our financial position and results of operations.

Our operations may be materially adversely affected by weather-related events, including, but not limited to, tropical storms and hurricanes, and the physical effects of climate change.

Tropical storms, hurricanes and the threat of tropical storms and hurricanes often result in the shutdown of operations, particularly in the Gulf of America, as well as operations within the path and the projected path of the tropical storms or hurricanes. In addition, the physical impacts of climate change in the areas in which our assets are located or in which we otherwise operate, including any corresponding increases to the severity and frequency of storms, floods and other weather events, could adversely impact our operations or disrupt transportation or other process‑related services provided by our third‑party contractors. Weather events have caused significant disruption to the operations of offshore and coastal facilities in the Gulf of America region. In the future, during a shutdown period, we may be unable to access well sites and our services may be shut down. Additionally, tropical storms or hurricanes may cause evacuation of personnel and damage to our platforms and other equipment, which may result in suspension of our operations. The shutdowns, related evacuations and damage can create unpredictability in activity and utilization rates, as well as delays and cost overruns, which could have a material adverse effect on our business, financial condition and results of operations.

The development schedule of oil and natural gas projects, including the availability and cost of drilling rigs, equipment, supplies, personnel and oilfield services, is subject to delays and cost overruns.

Historically, some oil and natural gas development projects have experienced delays and capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel and oilfield services, mechanical and technical issues, as well as weather-related delays. The cost to develop our projects has not been fixed and remains dependent upon a number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. Our construction and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available in a timely and cost‑effective fashion.

Our offshore and deepwater operations involve special risks that could adversely affect our results of operations.

Offshore operations are subject to a variety of special operating risks specific to the marine environment, such as capsizing, sinking, collisions and damage or loss to pipeline, subsea or other facilities or from weather conditions. We could incur substantial expenses that could reduce or eliminate the funds available for exploration, development or license acquisitions, or result in loss of equipment and license interests.

Deepwater exploration generally involves greater operational and financial risks than exploration in shallower waters. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of equipment failure and usually higher drilling costs. In addition, there may be production risks of which we are currently unaware. If we participate in the development of new subsea infrastructure and use floating production systems to transport oil from producing wells, these operations may require substantial time for installation or encounter mechanical difficulties and equipment failures that could result in loss of production, significant liabilities, cost overruns or delays. For example, we have previously experienced mechanical issues at certain of our offshore production facilities, such as the turret bearing issue on the Jubilee FPSO. The equipment downtime caused by these mechanical issues negatively impacted oil production.

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Furthermore, deepwater operations generally, and operations in Africa, in particular, lack the physical and oilfield service infrastructure present in other regions. As a result, a significant amount of time may elapse between a deepwater discovery and the marketing of the associated oil and natural gas, increasing both the financial and operational risks involved with these operations. Because of the lack and high cost of this infrastructure, further discoveries we may make in Africa may never be economically producible.

In addition, in the event of a well control incident, containment and, potentially, cleanup activities for offshore drilling are costly. The resulting regulatory costs or penalties, and the results of third-party lawsuits, as well as associated legal and support expenses, including costs to address negative publicity, could well exceed the actual costs of containment and cleanup. As a result, a well control incident could result in substantial liabilities, and have a significant negative impact on our earnings, cash flows, liquidity, financial position, and stock price.

We have had, and may in the future have, disagreements with certain host governments and contractual counterparties regarding certain of our rights and responsibilities.

There can be no assurance that disagreements will not arise with any host government, national oil companies, and/or contractual counterparties that may have a material adverse effect on our exploration, development or production activities, our ability to operate, our rights under our licenses and local laws or our rights to monetize our interests, but if such disagreements do arise we intend to vigorously dispute them if necessary.

The geographic locations of our licenses in Africa and the Gulf of America subject us to a risk of loss of revenue or curtailment of production from factors specifically affecting those areas.

A large portion of our current exploration licenses are located in Africa and a significant proportion of our total production comes from the Jubilee Unit Area and TEN Fields offshore Ghana. Some or all of these licenses could be affected should any region experience any of the following factors (among others):

• severe weather, natural or man‑made disasters or acts of God;

• delays or decreases in production, the availability of equipment, facilities, personnel or services;

• delays or decreases in the availability of capacity to transport, gather or process production;

• military conflicts, civil unrest or political strife; and/or

• international border disputes.

For example, oil and natural gas operations in our license areas in Africa may be subject to higher political and security risks than those operations under the sovereignty of the United States.

We plan to maintain insurance coverage for only a portion of the risks we face from doing business in these regions. There also may be certain risks covered by insurance where the policy does not reimburse us for all of the costs related to a loss. Further, as many of our licenses are concentrated in the same geographic area, a number of our licenses could experience the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of licenses.

Risks Relating to our Business and Financial Condition

A substantial or extended decline in both global and local oil, natural gas and LNG prices may adversely affect our business, financial condition and results of operations.

The prices that we will receive for our oil, natural gas, and LNG will significantly affect our revenue, profitability, access to capital and future growth rate. Historically, the oil and natural gas markets have been volatile and will likely continue to be volatile in the future. Oil, natural gas and LNG prices experienced significant volatility in the past few years and will likely continue to be volatile in the future. For example, Russia’s continued war in Ukraine, ongoing instability in the Middle East and Latin America, a potential regional or global recession, inflationary pressures and other varying macroeconomic conditions and the effects on demand for oil and natural gas has resulted in significant variations in oil, natural gas and LNG prices. The prices that we will receive for our production and the levels of our production depend on numerous factors. These factors include, but are not limited to, the following:

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• changes in supply and demand for oil, natural gas, and LNG;

• the actions of the Organization of the Petroleum Exporting Countries;

• speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

• global economic conditions;

• political and economic conditions, including embargoes in oil‑producing countries or affecting other oil‑producing activities, particularly in the Middle East, Africa, Russia and Central and South America;

• the continued threat of terrorism and the impact of military and other action, including U.S. military operations outside the United States in oil producing nations such as Venezuela and Iran;

• the level of global oil and natural gas exploration and production activity;

• the level of global oil inventories and oil refining capacities;

• weather conditions and natural or man‑made disasters;

• technological advances affecting energy consumption;

• governmental regulations and taxation policies;

• proximity and capacity of transportation facilities;

• the development and exploitation of alternative fuels or energy sources;

• the price and availability of competitors’ supplies of oil and natural gas; and

• the price, availability or mandated use of alternative fuels or energy sources.

Lower oil prices may not only reduce our revenues but also may limit the amount of oil and LNG that we can produce economically. A substantial or extended decline in oil, natural gas, and LNG prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. Additionally, a substantial or extended decline in oil, natural gas and LNG prices could result in surety companies seeking additional collateral to support existing surety or performance bonds, such as cash or letters of credit, and we cannot provide assurance that we will be able to satisfy such collateral demands. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing or obtain surety or performance bonds on commercially reasonable terms, we may be forced to reduce our capital expenditures. These factors may make it more difficult for us to obtain the financial assurances required by the BOEM to conduct operations in the Gulf of America. These difficulties could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms or at all in the future, which may in turn limit our ability to develop our exploration, appraisal, development and production activities.

We expect our capital outlays and operating expenditures to be substantial as we expand our operations. Obtaining seismic data, as well as exploration, appraisal, development and production activities entail considerable costs, and we may need to raise substantial additional capital through additional debt financing, asset sales, strategic alliances or future private or public equity offerings if our cash flows from operations, or the timing of, are not sufficient to cover such costs.

Our future capital requirements will depend on many factors, including:

• the scope, rate of progress and cost of our exploration, appraisal, development and production activities;

• the success of our exploration, appraisal, development and production activities;

• oil, natural gas, and LNG prices;

• our ability to locate and acquire hydrocarbon reserves;

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• our ability to produce oil or natural gas from those reserves;

• the terms and timing of any drilling and other production‑related arrangements that we may enter into;

• the cost and timing of governmental approvals and/or concessions;

• inflationary pressures leading to increasing costs;

• the effects of competition by other companies operating in the oil and gas industry; and

• potential changes in investor and public preferences and sentiment towards ESG considerations including climate change and the transition to a lower carbon economy.

We do not currently have any commitments for future external funding beyond the capacity of our commercial debt facility. Additional financing may not be available on favorable terms, or at all. Even if we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm‑out interests in our licenses, we would dilute our ownership interest subject to the farm‑out and any potential value resulting therefrom, and may lose operating control or influence over such license areas.

Assuming we are able to commence exploration, appraisal, development and production activities or successfully exploit our licenses during the exploratory term, our interests in our licenses (or the development/production area of such licenses as they existed at that time, as applicable) could extend beyond the term set for the exploratory phase of the license to a fixed period or life of production, depending on the jurisdiction. If we are unable to meet our well commitments and/or declare commerciality of the prospective areas of our licenses during this time, we may be subject to significant potential forfeiture of all or part of the relevant license interests. If we are not successful in raising additional capital, we may be unable to continue our exploration and production activities or successfully exploit our license areas, and we may lose the rights to develop these areas. See “—Under the terms of certain of our petroleum contracts, we are contractually obligated to drill wells and declare any discoveries in order to retain exploration and production rights. In the competitive market for our license areas, failure to drill these wells or declare any discoveries may result in substantial license renewal costs or loss of our interests in the undeveloped parts of our license areas, which may include certain of our prospects or undeveloped discoveries.”

All of our proved reserves, oil and natural gas production and cash flows from operations are currently associated with our licenses offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Should any event occur which adversely affects such proved reserves, production and cash flows from these licenses, including, without limitation, any event resulting from the risks and uncertainties outlined in this “Risk Factors” section, our business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures may be materially and adversely affected.

We may be required to take write‑downs of the carrying values of our oil and natural gas assets due to decreases in the estimated future net cash flows from our operations, which may occur as a result of decreases in oil, natural gas, and LNG prices, poor field performance, increased expenditures or changes in the timing or amount of investment, among other things, and such decreases could result in reduced availability under our commercial debt facility.

We capitalize costs to acquire, find and develop our oil and natural gas properties under the successful efforts accounting method. Under such method, we are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of appraisal and development plans, production data, oil, natural gas, and LNG prices, economics and other factors, we may be required to write down the carrying value of our oil and natural gas assets. A write‑down constitutes a non‑cash charge to earnings. For example, if there is a significant and sustained drop in oil, natural gas, and LNG prices, field performance is not as expected, or we encounter increased expenditures, we may incur future write‑downs and charges.

In addition, our borrowing base under the commercial debt facility is subject to periodic redeterminations. We could be forced to repay a portion of our borrowings under the commercial debt facility due to redeterminations of our borrowing base. Redeterminations may occur as a result of a variety of factors, including oil and natural gas commodity price assumptions, assumptions regarding future production from our oil and natural gas assets, operating costs and tax burdens or assumptions concerning our future holdings of proved reserves. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new

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financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We face various risks associated with increased activism against, or change in public sentiment for, oil and gas exploration development, and production activities and ESG considerations, including climate change and the transition to a lower carbon economy.

Opposition toward oil and gas drilling, development, and production activity has been growing globally. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non‑governmental organizations and other stakeholders regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Certain of these activists are working to, among other things, delay or cancel certain operations such as offshore drilling and development.

Future activist efforts could result in the following:

• delay or denial of drilling permits;

• shortening of lease terms or reduction in lease size;

• restrictions or delays on our ability to obtain additional seismic data;

• restrictions on installation or operation of gathering or processing facilities;

• restrictions on the use of certain operating practices;

• legal challenges or lawsuits;

• pressure or requirements for more analysis and disclosure of environmental and climate change-related risks and data, such as greenhouse gas emissions data;

• damaging publicity about us;

• increased regulation;

• increased costs of doing business;

• reduced access to financing and hedging;

• reduction in demand for our products; and

• other adverse effects on our ability to develop our properties and/or undertake production operations.

Our need to incur costs associated with responding to these initiatives or complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations. In addition, a change in public sentiment regarding the oil and gas industry could result in a reduction in the demand for our products or otherwise affect our results of operations or financial condition.

Outbreaks of disease may adversely affect our business operations and financial condition.

Significant outbreaks of contagious diseases such as COVID-19, and other adverse public health developments, could have a material impact on our business operations and financial condition. Many of our operations are currently, and will likely remain in the near future, in developing countries which are susceptible to outbreaks of disease, such as the Ebola virus disease, and may lack the resources to effectively contain such an outbreak quickly. Such outbreaks may impact our ability to explore for oil and gas, develop or produce our license areas by limiting access to qualified personnel, increasing costs associated with ensuring the safety and health of our personnel, restricting transportation of personnel, equipment, supplies and oil and gas production to and from our areas of operation and diverting the time, attention and resources of government agencies which are necessary to conduct our operations. In addition, any losses we experience as a result of such outbreaks of disease which impact sales or delay production may not be covered by our insurance policies.

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Our operations require contractors and personnel to travel to and from Africa as well as the unhindered transportation of equipment and oil and gas production (in the case of our producing fields). Such operations also rely on infrastructure, contractors and personnel in Africa. If travel bans in response to outbreaks of disease are implemented or extended to the countries in which we operate, or contractors or personnel refuse to travel there, we could be adversely affected. If services are obtained, costs associated with those services could be significantly higher than planned which could have a material adverse effect on our business, results of operations, and future cash flow. In addition, should an Ebola or other virus outbreak spread to the countries in which we operate, access to the FPSOs could be restricted and/or terminated. The FPSOs are potentially able to operate for a short period of time without access to the mainland, but if restrictions extended for a longer period we and the operator of the impacted fields would likely be required to cease production and other operations until such restrictions were lifted.

These or any further political or governmental developments or health concerns could result in social, economic and labor instability. These uncertainties could have a material impact on our business operations and financial condition.

Deterioration in the credit or equity markets could adversely affect us.

We have exposure to different counterparties. For example, we have entered or may enter into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds, and other institutions. These transactions expose us to credit risk in the event of default by our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill existing obligations to us and their willingness to enter into future transactions with us. We may have exposure to these financial institutions through any derivative transactions we have or may enter into. Moreover, to the extent that purchasers of our future production, if any, rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to us if such purchasers were unable to access the credit or equity markets for an extended period of time.

We may incur substantial losses and become subject to liability claims as a result of future oil and natural gas operations, for which we may not have adequate insurance coverage.

We intend to maintain insurance against certain risks in the operation of the business we plan to develop and in amounts in which we believe to be reasonable. Such insurance, however, may contain exclusions and limitations on coverage or may not be available at a reasonable cost or at all. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. For example, recent increases in the cost of insurance coverage in the Gulf of America for Oil Spill Financial Responsibility requirements under the Oil Pollution Act of 1990 may result in Kosmos carrying lower insurance coverage than in previous years. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations. Further, even in instances where we maintain adequate insurance coverage, potential delays related to receipt of insurance proceeds as well as delays associated with the repair or rebuilding of damaged facilities could also materially and adversely affect our business, financial condition and results of operations.

Slower global economic growth rates may materially adversely impact our operating results and financial position.

Market volatility and reduced consumer demand due to inflationary pressures, increased tariffs or otherwise may increase economic uncertainty. Global economic growth drives demand for energy from all sources, including hydrocarbons. A lower future economic growth rate is likely to result in decreased demand growth for crude oil and natural gas production. A decrease in demand, notwithstanding impacts from other factors, could potentially result in lower commodity prices, which would reduce our cash flows from operations, our profitability and our liquidity and financial position.

Increased costs and availability of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

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Our derivative activities could result in financial losses or could reduce our income.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil, natural gas and LNG, we have and may in the future enter into derivative arrangements for a portion of our oil and natural gas production, including, but not limited to, puts, collars and fixed‑price swaps. In addition, we have and may in the future enter into derivative arrangements designed to hedge our interest rate risk. We do not currently designate any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

• production is less than the volume covered by the derivative instruments;

• the counter‑party to the derivative instrument defaults on its contract obligations; or

• there is an increase in the differential between the underlying price and actual prices received in the derivative instrument.

These types of derivative arrangements may limit the benefit we could receive from increases in the prices for oil, natural gas and LNG or beneficial interest rate fluctuations and may expose us to cash margin requirements. In addition, a reduction in our ability to access credit could reduce our ability to implement derivative arrangements on commercially reasonable terms.

Our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes contain certain covenants that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our future goals.

Our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes include certain covenants that, among other things, restrict:

• our investments, loans and advances and certain of our subsidiaries’ payment of dividends and other restricted payments;

• our incurrence of additional indebtedness;

• the granting of liens, other than liens created pursuant to the commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds or the indentures governing our Senior Notes and Convertible Senior Notes and certain permitted liens;

• mergers, consolidations and sales of all or a substantial part of our business or licenses;

• the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;

• the sale of assets (other than production sold in the ordinary course of business); and

• in the case of the commercial debt facility and the GoA Term Loan Facility, our capital expenditures that we can fund with the proceeds of our commercial debt facility and GoA Term Loan Facility.

Our commercial debt facility, the bond terms governing our GTA Nordic bonds and GoA Term Loan Facility require us to maintain certain financial ratios, such as asset coverage ratios, debt service coverage ratios and cash flow coverage ratios. All of these restrictive covenants may limit our ability to move funds among our subsidiaries, operate our business, or expand or pursue our business strategies. Our ability to comply with these and other provisions of our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes may be impacted by changes in economic or business conditions, our results of operations or events beyond our control. The breach of any of these covenants could result in a default under our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes, in which case, depending on the actions taken by the lenders thereunder or their successors or assignees, such lenders could elect to declare all amounts borrowed under such debt instruments, together with accrued interest,

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to be due and payable. If we were unable to repay such borrowings or interest, our lenders, successors or assignees could proceed against their collateral. If the indebtedness under our commercial debt facility, GoA Term Loan Facility, the bond terms governing our GTA Nordic bonds and the indentures governing our Senior Notes and Convertible Senior Notes were to be accelerated, our assets may not be sufficient to repay in full such indebtedness. In addition, the limitations imposed by such debt instruments on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing.

Provisions of our Senior Notes and Convertible Senior Notes could discourage an acquisition of us by a third-party.

Certain provisions of the indentures governing our Senior Notes and Convertible Senior Notes could make it more difficult or more expensive for a third-party to acquire us, or may even prevent a third-party from acquiring us. For example, upon the occurrence of a “change of control triggering event” (as defined in the indentures governing our Senior Notes), holders of the notes will have the right, at their option, to require us to repurchase all of their notes or any portion of the principal amount of such notes. In addition, upon the occurrence of a “fundamental change” (as defined in the indenture governing our Convertible Senior Notes) holders of the notes will have the right, at their option, to require us to repurchase all of their notes or any portion of the principal amount of such notes. By discouraging an acquisition of us by a third-party, these provisions could have the effect of depriving the holders of our common stock of an opportunity to sell their common stock at a premium over prevailing market prices.

Our level of indebtedness may increase and thereby reduce our financial flexibility.

At December 31, 2025, we had $1,200.0 million outstanding and $150.0 million of committed undrawn available capacity under our commercial debt facility. As of December 31, 2025, we had $1.8 billion principal amount of Senior Notes and Convertible Senior Notes outstanding and $150 million outstanding under the GoA Term Loan Facility. In the future, we also may incur significant off-balance sheet obligations and/or significant indebtedness in order to make investments or acquisitions or to explore, appraise or develop our oil and natural gas assets.

Our level of indebtedness could affect our operations in several ways, including the following:

• a significant portion or all of our cash flows, when generated, could be used to service our indebtedness;

• a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions;

• the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

• a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing;

• our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

• additional hedging instruments may be required as a result of our indebtedness;

• a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then‑outstanding bank borrowings; and

• a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future economic performance. General economic conditions, risks associated with exploring for and producing oil and natural gas, oil, natural gas, and LNG prices and financial, business and other factors affect our operations and our future economic performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our indebtedness and future working capital, borrowings or equity financing may not be available to pay or refinance such indebtedness. Factors that will affect our ability to raise cash through an offering of our equity securities or a refinancing of our indebtedness include financial market conditions, the value of our assets and our performance at the time we need capital.

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We are a holding company and our ability to make payments on our outstanding indebtedness, including our Senior Notes and Convertible Senior Notes, is dependent upon the receipt of funds from our subsidiaries by way of dividends, fees, interest, loans or otherwise.

We are a holding company, and our subsidiaries own all of our assets and conduct all of our operations. Accordingly, our ability to make payments of interest and principal on our outstanding indebtedness, including the Senior Notes and Convertible Senior Notes, will be dependent on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors, our subsidiaries will not have any obligation to pay amounts due on the Senior Notes and Convertible Senior Notes or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of the Senior Notes and Convertible Senior Notes. Each subsidiary is a distinct legal entity and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. The indentures governing our Senior Notes and Convertible Senior Notes limit the ability of our subsidiaries to incur consensual encumbrances or restrictions on their ability to pay dividends or make other intercompany payments to us, with significant qualifications and exceptions. In addition, the terms of the commercial debt facility limit the ability of the obligors thereunder, including our material operating subsidiaries that hold interests in our assets located offshore Ghana and Equatorial Guinea and their intermediate parent companies to provide cash to us through dividend, debt repayment or intercompany lending. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the Senior Notes and Convertible Senior Notes.

We may be subject to risks in connection with acquisitions and the integration of acquisitions may be difficult.

We periodically evaluate acquisitions of prospects and licenses, reserves and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of these assets or businesses requires an assessment of several factors, including:

• recoverable reserves;

• future oil, natural gas and LNG prices and their appropriate differentials;

• development and operating costs; and

• potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject assets that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the assets to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We may not be entitled to contractual indemnification for environmental liabilities and could acquire assets on an “as is” basis. Acquisitions and other strategic transactions may involve other risks, including:

• diversion of our management’s attention to evaluating, negotiating and integrating acquisitions and strategic transactions;

• the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

• difficulty associated with coordinating geographically separate organizations; and

• the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of acquisitions, our results of operations may be adversely affected.

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The success of an acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, increased interest expense associated with debt incurred or assumed in connection with the transaction, adverse changes in oil and gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties, including the assumption of health, safety, and environmental or other liabilities in connection with the acquisition. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

A cybersecurity incident, including a breach of digital security, could result in information theft, data corruption, operational disruption, and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day‑to‑day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, co‑venturers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, such as deepwater, and global competition for oil and gas resources make certain information more attractive to thieves.

As dependence on digital technologies has increased, cybersecurity incidents, including deliberate attacks or unintentional events, have also increased. A cyber‑attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or personal, confidential or proprietary information, corrupting data, or causing operational disruption, or result in denial‑of‑service on websites. For example, in 2021, the Colonial Pipeline was subject to a ransomware attack that disabled the pipeline for several days, affecting consumers throughout the eastern coast of the United States. A number of U.S. companies have also been subject to cyber-attacks in recent years resulting in unauthorized access to personal, confidential or proprietary information and operational disruptions. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies.

Our technologies, systems, networks, and those of our business partners may become the target of cyber‑attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of personal, confidential, proprietary and other information, or other disruption of our business operations. In addition, certain cybersecurity incidents, such as surveillance, may remain undetected for an extended period. A cybersecurity incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans, harm our reputation and negatively impact our operations. We expect to maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events, whether or not covered by insurance, could have a material adverse effect on our financial position and results of operations. Although to date we have not experienced any material cyber‑attacks, there can be no assurance that we will not be the target of cyber‑attacks in the future or suffer such losses related to any cyber‑incident. As cybersecurity threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

We are incorporating artificial intelligence technologies into our processes and these technologies may present business, operational, compliance, cybersecurity, and reputational risks.

Our business increasingly utilizes artificial intelligence (“AI”), machine learning, and automated decision making to improve our internal processes and support operational and strategic decisions. The development, deployment and use of these technologies, combined with an evolving and uncertain regulatory environment, may result in new or heightened governmental or regulatory scrutiny, litigation, confidentiality or security risks, reputational harm, liability or other adverse consequences to our business operations, any of which could adversely affect our business, financial condition and results of operations.

The use of AI tools can lead to unintended consequences, including the unauthorized use or disclosure of confidential and proprietary information, or the generation of content or outputs that appear correct but are factually inaccurate, misleading,

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or otherwise flawed. Reliance on such outputs could expose us to risks related to inaccuracies or errors in the output of such technologies. We have established an internal, cross-functional AI committee to oversee and guide our AI strategy including evaluating the costs, benefits, risks, and opportunities associated with the use of AI tools in our business and recommending mitigation measures, as well as developing and implementing an AI use policy across the Company. However, these governance measures may not be effective in all cases, and it is not possible to predict or prevent all of the risks related to the use of AI, machine learning, and automated decision making technologies. In addition, future changes in laws or developments in the regulatory frameworks governing the use of such technologies and in related stakeholder expectations could restrict or limit our use of AI, increase our compliance costs, or subject us to liability, any of which could adversely affect our ability to develop and use such technologies.

Our ability to utilize net operating loss carryforwards may be subject to certain limitations.

Our ability to use our federal and international net operating losses to offset potential future taxable income and related income taxes that would otherwise be due is dependent upon our generation of future taxable income and we cannot predict with certainty when, or whether, we will generate sufficient taxable income to use all of our net operating losses. In addition, with regard to our U.S. net operating losses only, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), contains rules that impose an annual limitation on the ability of a company with federal net operating loss carryforwards that undergoes an ownership change, which is generally any change in ownership of more than 50% of its stock (by value) over a three-year period, to utilize its federal net operating loss carryforwards in years after the ownership change. These rules generally operate by focusing on ownership changes among holders owning directly or indirectly 5% or more of the shares of stock of a company or any change in ownership arising from a new issuance of shares of stock by such company.

If we were to undergo an ownership change as a result of future transactions involving our common stock, including a follow-on offering of our common stock or purchases or sales of common stock between 5% holders, our ability to use our federal net operating loss carryforwards may be subject to limitation under Section 382 of the Code. If our federal net operating losses become subject to the limitation under Section 382 of the Code, we may be unable to fully utilize our federal net operating loss carryforwards to offset our taxable income, if any, in future years, which could have a negative impact on our financial position and results of operations.

In addition to the aforementioned federal income tax implications pursuant to Section 382 of the Code, most states follow the general provisions of Section 382 of the Code, either explicitly or implicitly resulting in separate state net operating loss limitations. Any limitation on our ability to use our state net operating loss carryforwards could also have a negative impact on our financial position and results of operations.

Risks Relating to Regulation

Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic, and environmental circumstances, and changes in laws and regulations, in the countries and regions in which we operate.

Oil and natural gas exploration, development and production activities are directly and indirectly subject to political, economic, and environmental uncertainties (including but not limited to those resulting from government elections and changes in energy policies), changes in laws and policies governing operations of companies, expropriation of property, cancellation or modification of contract rights, revocation of consents, approvals or royalty regimes, obtaining various approvals from regulators, foreign exchange restrictions, currency fluctuations, royalty increases, implementation of a carbon tax or cap-and-trade program, increased laws and regulations around climate change, and other risks arising out of governmental sovereignty, as well as risks of loss due to civil strife, acts of war, guerrilla activities, terrorism, acts of sabotage, territorial disputes and insurrection.

In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and where we are resident for tax purposes and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in our tax liabilities. These risks may be higher in the developing countries in which we conduct a majority of our activities.

Additionally, monetary sector reform initiatives in the West African Monetary Union and the Central African Economic and Monetary Union, such as through the implementation of Regulation 02/18/ECMAC/UMAC/CM by the Bank of Central African States could restrict or prevent payments being made in a foreign currency; impose restrictions on offshore and onshore foreign currency accounts; and/or restrict or prevent the repatriation of revenues and debt proceeds. The attempted imposition of or the implementation or realization of any of the foregoing could have an adverse impact on our financial condition and results of operations. For example, compliance with West African Monetary Union Regulations in Senegal could

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result in our exposure to, among other things, foreign exchange risks/costs and impact the efficiency of moving cash balances in and out of country.

Our operations in these areas increase our exposure to risks of war, local economic conditions, political disruption, civil disturbance, expropriation, piracy, tribal conflicts and governmental policies that may:

• disrupt our operations;

• require us to incur greater costs for security;

• impact our credit ratings and ability to access capital;

• restrict the movement of funds or limit repatriation of profits;

• lead to U.S. government or international sanctions; or

• limit access to markets for periods of time.

Some countries in the geographic areas where we operate have experienced political instability in the past or are currently experiencing instability. Disruptions may occur in the future, and losses caused by these disruptions may occur that will not be covered by insurance. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on our results of operations and financial condition. Furthermore, in the event of a dispute arising from non‑U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non‑U.S. persons to the jurisdiction of courts in the United States or international arbitration, which could adversely affect the outcome of such dispute.

Our operations may also be adversely affected by laws and policies of the jurisdictions, including the jurisdictions where our oil and gas operating activities are located as well as the United Kingdom and the Cayman Islands and other jurisdictions in which we do business, that affect foreign trade and taxation. Changes in any of these laws or policies or the implementation thereof could materially and adversely affect our financial position, results of operations and cash flows.

More comprehensive and stringent regulation in the Gulf of America has materially increased costs and delays in offshore oil and natural gas exploration and production operations.

In the Gulf of America, regulatory initiatives are continually developed and implemented at the federal level to prevent major well control incidents. The Department of Interior (“DOI”) through the BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”), has issued a variety of regulations and Notices to Lessees and Operators (“NTLs”), intended to impose additional safety, permitting and certification requirements applicable to exploration, development and production activities in the Gulf of America. These regulatory initiatives have, at various times, effectively slowed down the pace of drilling and production operations in the Gulf of America as adjustments were being made in operating procedures, certification requirements and lead times for inspections, drilling applications and permits, and exploration and production plan reviews, and as the federal agencies evolved into their present-day bureaus. On May 15, 2019, BSEE published a final rule with an effective date of July 15, 2019 that revised requirements for well design, well control, casing, cementing, real-time monitoring (RTM), and subsea containment. These revisions modified regulations pertaining to offshore oil and gas drilling, completions, workovers, and decommissioning in accordance with Executive and Secretary of the Interior's Orders. Key features of the well control regulations include requirements for blowout preventers (BOPs), double shear rams, third-party reviews of equipment, real time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment. Since adoption of the 2019 rule, BSEE has adopted additional well control requirements and continues to evaluate and implement further regulatory initiatives applicable to offshore oil and gas operations through amendments, guidance and ongoing or anticipated rulemakings.

In addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in recent years, there have been a variety of proposals and initiatives to change existing laws, regulations and agency practices that could affect offshore development and production, such as, for example, proposals to increase or otherwise revise the minimum financial responsibility or other security required under the Oil Pollution Act of 1990 or otherwise applicable to offshore lessees and operators. Regulatory initiatives relating to financial assurance, bonding and other forms of security continue to evolve. For example, in 2024, the DOI finalized an offshore financial assurance rule that increased bonding and other financial responsibility requirements for certain offshore lessees and operators. In 2025, the DOI announced plans to revise this rule as part of a broader review of offshore financial assurance requirements. Any changes to the rule, or

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uncertainty regarding its implementation, could affect our financial assurance obligations, compliance costs and offshore development activities.

To the extent the existing regulatory initiatives implemented and pursued in recent years or any future restrictions, whether through legislative or regulatory means or increased or broadened permitting and enforcement programs, foster uncertainties, delays or increased costs in our offshore oil and natural gas development or exploration activities, then such conditions may have a material adverse effect on our business, financial condition and results of operations. Any other new rules, regulations or legal initiatives by BOEM or other governmental authorities that impose more stringent requirements regarding financial assurances, restrict or delay leasing or permitting or that otherwise adversely affect our offshore activities could result in increased costs, limit our operations and adversely impact our future financial results.

The oil and gas industry, including the acquisition of exploratory licenses, is intensely competitive and many of our competitors possess and employ substantially greater resources than us.

The oil and gas industry is highly competitive in all aspects, including the exploration for, and the development of, new license areas. We operate in a highly competitive environment for acquiring exploratory licenses and hiring and retaining trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than us, which can be particularly important in the areas in which we operate. These companies may be better able to withstand the financial pressures of unsuccessful drilling efforts, sustained periods of volatility in financial markets and generally adverse global and industry‑wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which could adversely affect our competitive position. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable licenses and to consummate transactions in a highly competitive environment. Also, there is substantial competition for available capital for investment in the oil and gas industry. As a result of these and other factors, we may not be able to compete successfully in an intensely competitive industry, which could cause a material adverse effect on our results of operations and financial condition.

Participants in the oil and gas industry are subject to numerous laws, regulations, and other legislative instruments that can affect the cost, manner or feasibility of doing business.

Exploration and production activities in the oil and gas industry are subject to local laws and regulations. We may be required to make large expenditures to comply with governmental laws and regulations, particularly in respect of the following matters:

• licenses for drilling operations;

• tax increases, including retroactive claims;

• unitization of oil accumulations;

• local content requirements (including the mandatory use of local partners and vendors); and

• safety, health and environmental requirements, liabilities and obligations, including those related to remediation, investigation or permitting.

Under these and other laws and regulations, we could be liable for personal injuries, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change, or their interpretations could change, in ways that could substantially increase our costs. These risks may be higher in the developing countries in which we conduct a majority of our operations, where there could be a lack of clarity or lack of consistency in the application of these laws and regulations. Any resulting liabilities, penalties, suspensions or terminations could have a material adverse effect on our financial condition and results of operations.

We are subject to numerous health, safety and environmental laws and regulations which may result in material liabilities and costs.

We are subject to various international, foreign, federal, state and local health, safety and environmental laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water, the generation, storage, handling, use, transportation and disposal of regulated materials and the health and safety of our employees, contractors and communities in which our assets are located. We are required to obtain environmental permits from

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governmental authorities for our operations, including drilling permits for our wells. We maintain policies and processes to comply with these various permits and laws and regulations to which we are subject. If determined that we have violated or failed to comply with such requirements, we could be fined or otherwise sanctioned by regulators, including through the revocation of our permits or the suspension or termination of our operations. Additionally, there is a risk that such requirements could change in the future or become more stringent. If we fail to obtain, maintain or renew permits in a timely manner or at all (due to opposition from partners, community or environmental interest groups, governmental delays or other reasons), or if we face additional requirements imposed as a result of changes in or enactment of laws or regulations, such failure to obtain, maintain or renew permits or such changes in or enactment of laws or regulations could impede or affect our operations, which could have a material adverse effect on our results of operations and financial condition.

We, as an interest owner or as the designated operator of certain of our past, current and future interests, discoveries and prospects, could be held liable for some or all health, safety and environmental costs and liabilities arising out of our actions and omissions as well as those of our block partners, third‑party contractors, predecessors or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended or terminated. We have contracted with and intend to continue to hire third parties to perform services related to our operations. There is a risk that we may contract with third parties with unsatisfactory health, safety and environmental records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. Accordingly, we could be held liable for all costs and liabilities arising out of their acts or omissions, which could have a material adverse effect on our results of operations and financial condition.

We are not fully insured against all risks and our insurance may not cover any or all health, safety or environmental claims that might arise from our operations or at any of our license areas. If a significant accident or other event occurs and is not covered by insurance, such accident or event could have a material adverse effect on our results of operations and financial condition.

We take measures to prevent the release of regulated substances. If a release of regulated substances were to occur, which may be significant, under certain environmental laws, we could be held responsible for all of the costs relating to any contamination at our current or former facilities and at any third-party waste disposal sites used by us or on our behalf. In addition, offshore oil and natural gas exploration and production involves various hazards, including human exposure to regulated substances, which include naturally occurring radioactive, and other materials. As such, we could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of any regulated or otherwise hazardous substances to the environment, property or to natural resources, or affecting endangered species.

In addition, we expect continuing attention to climate change and energy transition issues. For example, in April 2016, 195 nations, including Ghana, Mauritania, Sao Tome and Principe, Senegal and the United States, signed and officially entered into an international climate change accord (the “Paris Agreement”). The Paris Agreement calls for signatory countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG targets. A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. In January 2026, President Trump once again withdrew the United States from the Paris Agreement, as he did during his first term. Separately, in December 2023, the U.S. EPA announced its final rule regulating methane and volatile organic compounds emissions in the oil and gas industry which, among other things, requires periodic inspections to detect leaks (and subsequent repairs), places stringent restrictions on venting and flaring of methane, and establishes a program whereby third parties can monitor and report large methane emissions to the EPA. Relatedly, in November 2024, the U.S. EPA finalized a rule implementing the Waste Emissions Charge, a fee for large emitters of methane if their emissions exceed certain levels, as required by the Inflation Reduction Act. In addition, numerous other climate change and GHG emissions laws, regulations or rules have been proposed or are in various stages of review and/or challenge. It cannot be determined at this time what effect these various climate change and GHG emissions-related developments will have on our business, results of operations and financial condition. This legislative and regulatory uncertainty, however, could result in a disruption to our business or operations.

Health, safety and environmental laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Our costs of complying with current and future climate change, health, safety and environmental laws, the actions or omissions of our block partners and third-party contractors and our liabilities arising from releases of, or exposure to, regulated substances may adversely affect our results of operations and financial condition. See “Item 1. Business—Environmental Matters” for more information.

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We may be exposed to assertions concerning or liabilities under the U.S. Foreign Corrupt Practices Act and other anti‑corruption laws, and any such assertions or determination that we violated the U.S. Foreign Corrupt Practices Act or other such laws could result in significant costs to Kosmos and have a material adverse effect on our business.

We are subject to the U.S. Foreign Corrupt Practices Act (“FCPA”) and other laws that prohibit improper payments or offers of payments to foreign government officials and political parties for the purpose of obtaining or retaining business or otherwise securing an improper business advantage. In addition, the United Kingdom has enacted the Bribery Act of 2010, and we may be subject to that legislation under certain circumstances. We do business and may do additional business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials. We face the risk of unauthorized payments or offers of payments by one of our employees, contractors or consultants. Our existing safeguards and any future improvements may prove to be less than effective in preventing such unauthorized payments, and our employees and consultants may engage in conduct for which we might be held responsible. Violations of the FCPA or other anti-corruption laws may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the U.S. government may seek to hold us liable for successor liability for FCPA violations committed by companies in which we invest (for example, by way of acquiring equity interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions with) or that we acquire.

While we believe we maintain a robust compliance program (including policies, procedures, and controls) and corresponding compliance culture, from time-to-time assertions may be raised, including by media outlets or competitors, related to our operations or assets which, notwithstanding the lack of veracity of such assertions, may attract the interest of regulators or affect the market perception of Kosmos.

Federal regulatory law could have an adverse effect on our ability to use derivatives to reduce the effect of commodity price, interest rate and other risks associated with our business.

At times, we use derivatives, specifically cash-settled commodity options and interest rate swaps, to hedge risks associated with our business, including commodity price and interest rate risk. The Commodity Futures Trading Commission (“CFTC”) has jurisdiction over derivatives, including swaps and cash-settled commodity options, which are regulated as swaps under the Commodity Exchange Act.

Of particular importance to us, the CFTC has implemented regulations that establish position limits for certain futures and economically equivalent swaps and require exchanges to do the same. Certain bona fide hedging positions are exempt from these position limits. As the relevant provisions of these rules for the Company are phased in over the next several years, they may increase costs or, if we are unable to meet the specific requirements of the relevant hedging exemption, we may be subject to certain position limits.

The CFTC has designated certain interest rate swaps for mandatory clearing and exchange trading. The CFTC has not yet proposed rules designating any other classes of swaps, including commodity swaps, for mandatory clearing or exchange trading. The application of the mandatory clearing and trade execution requirements may change the cost and availability of the swaps that the Company uses for hedging.

Swap dealers that we transact with need to comply with margin and segregation requirements for uncleared swaps. While our uncleared swaps are not directly subject to those margin requirements as a result of the fact that they are used by us for hedging purposes, due to the increased costs to dealers for transacting uncleared swaps in general, our costs for these transactions may increase.

The Commodity Exchange Act also requires certain of the counterparties to our derivatives instruments to be registered with the CFTC and be subject to substantial regulation. These requirements could significantly increase the cost of derivatives, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivatives. If we reduce our use of derivatives as a result of these regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could also be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.

The European Union and other non‑U.S. jurisdictions have also implemented or are implementing similar regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we or our transactions may become subject to such regulations. The impact of such regulations could be similar to those described above with respect to U.S. rules.

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Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

General Risk Factors

We are dependent on certain members of our management and technical team.

Our performance and success largely depend on the ability, expertise, judgment and discretion of our management and the ability of our technical team to identify, discover, evaluate, develop, and produce reserves. The loss or departure of one or more members of our management and technical team could be detrimental to our future success. Additionally, a significant amount of shares in Kosmos held by members of our management and technical team has vested. There can be no assurance that our management and technical team will remain in place. If any of these officers or other key personnel retires, resigns or becomes unable to continue in their present roles and is not adequately replaced, our results of operations and financial condition could be materially adversely affected. Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

We operate in a litigious environment.

Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and gas companies, such as us, can be involved in various legal proceedings, such as title or contractual disputes, in the ordinary course of business.

From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes that the likelihood of an unfavorable outcome having a material impact is neither reasonably possible nor probable of occurring

Because we maintain a diversified portfolio of assets overseas, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability and/or negative publicity about us and adversely affect the price of our common stock. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

We face various risks associated with global activism.

Globally, certain individuals and organizations are attempting to focus public attention on income distribution, wealth distribution, and corporate taxation levels, and implement income and wealth redistribution policies. These efforts, if they gain political traction, could result in increased taxation on individuals and/or corporations, as well as, potentially, increased regulation on companies and financial institutions. Our need to incur costs associated with responding to these developments or complying with any resulting new legal or regulatory requirements, as well as any potential increased tax expense, could increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our business, financial condition and results of our operations.

Our share price may be volatile, and purchasers of our common stock could incur substantial losses.

Our share price may be volatile. The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. The market price for our common stock may be influenced by many factors, including, but not limited to:

• the price of oil, natural gas and LNG;

• the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;

• operational incidents;

• regulatory developments in the United States and foreign countries where we operate;

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• the recruitment or departure of key personnel;

• quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us;

• market conditions in the industries in which we compete and issuance of new or changed securities;

• analysts’ reports or recommendations;

• the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;

• the inability to meet the financial estimates of analysts who follow our common stock;

• the issuance or sale of any additional securities of ours;

• investor perception of our company and of the industry in which we compete; and

• general economic, political and market conditions.

Holders of our common stock will be diluted if additional shares are issued.

We may issue additional shares of common stock, securities that are convertible into shares of common stock, preferred shares, warrants, rights, units and debt securities for general corporate purposes, including, but not limited to, repayment or refinancing of borrowings, working capital, capital expenditures, investments and acquisitions. We continue to actively seek to expand our business through complementary or strategic acquisitions, and we may issue additional shares of common stock in connection with those acquisitions. We also issue restricted share units to our executive officers, employees and independent directors as part of their compensation. If we issue additional shares of common stock or securities that are convertible into shares of common stock in the future, it may have a dilutive effect on our current outstanding shareholders.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis contains forward‑looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward‑looking statements as a result of various factors, including, without limitation, those set forth in “Cautionary Statement Regarding Forward‑Looking Statements” and “Item 1A. Risk Factors.” The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this annual report on Form 10‑K.

Overview

Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, 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.

Recent Developments

Corporate

On September 24, 2025, the Company entered into a senior secured term loan credit agreement secured by first priority liens on all of the Company’s Gulf of America assets (as defined in the Credit Agreement). The GoA Term Loan Facility is a four-year term loan structured into two tranches, with the first tranche a principal amount of $150.0 million, which was funded in October 2025, and a second tranche of an additional $100.0 million, which was funded in January 2026. The net proceeds were used, together with cash on hand, to fund the redemption of the 7.125% Senior Notes due 2026 totaling $250.0 million in aggregate. The GoA Term Loan Facility is now fully drawn and matures in 2029, with principal payments beginning June 30, 2026.

On January 16, 2026, the Company announced the pricing of $350.0 million aggregate principal amount of 11.250% senior secured bonds due 2031 in the Nordic market (the “GTA Nordic bonds”). The GTA Nordic bonds are fully and unconditionally guaranteed by the Company, as well as the Company’s wholly-owned subsidiaries that own the Mauritania and Senegal assets. In February 2026, Kosmos used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of its 7.750% Senior Notes due 2027 and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility, with the remaining proceeds to be used for future retirements of the 7.750% Senior Notes due 2027.

In July 2025, new U.S. tax legislation was signed into law in the United States known as the “One Big Beautiful Bill Act” or “OBBBA”. The legislation includes a broad range of U.S. corporate tax reform provisions affecting businesses across numerous industries. The necessary adjustments have been reflected for the year ended December 31, 2025. Based on our evaluation, we have determined that the impact of OBBBA is not material to the Company’s financial position or results.

Ghana

During the year ended December 31, 2025, Ghana production averaged approximately 93,100 Boepd gross (31,100 Boepd net).

The partnership completed a new 4D seismic survey on the Jubilee and TEN Fields during the first quarter of 2025 and an Ocean Bottom Node survey was completed in the fourth quarter of 2025. In the second quarter of 2025, we commenced the next development drilling campaign in the Jubilee Field. The Jubilee drilling progressed during the year bringing one producer well successfully online in July 2025. After undergoing scheduled maintenance, the rig returned to the Jubilee Field to drill an additional producer well, which was successfully completed and brought online in January 2026. The development drilling campaign will continue in 2026 by drilling four planned producer wells and an additional water injector well.

In June 2025, the Jubilee and TEN partnerships entered into a Memorandum of Understanding with the Government of Ghana to extend to 2040 the WCTP and the DT licenses, which cover the Jubilee and TEN fields offshore Ghana. The Ghana partnership received Government approval in December 2025 for the license extensions. Accordingly, the WCTP and DT licenses have been extended to 2040 and starting from July 2036, Ghana National Petroleum Corporation’s share in the fields will increase by an additional 10% interest and the joint venture partners’ shares will decrease pro rata. 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 fields. Additionally, in December 2025, as part of the extension of the WCTP and DT Petroleum Agreements, the Ghana partners and

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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.

In February 2026, the TEN partnership executed the final Sale and Purchase Agreement to acquire the TEN FPSO from MODEC, Inc. at the end of its current lease in 2027 for a gross purchase price of $205.0 million.

Gulf of America

During the year ended December 31, 2025, Gulf of America production averaged approximately 17,600 Boepd (net) (~84% oil).

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

In January 2026, Kosmos was awarded two lease blocks in the Gulf of America Big Beautiful Gulf Lease Sale 1 (“BBG1”).

At Winterfell, in October 2024, shortly after startup of the Winterfell-3 well, production at the field was curtailed due to sand production from the Winterfell-3. Production from the first two wells was restored in December 2024. Remediation work on Winterfell-3 was performed in the first quarter of 2025, however, it was unsuccessful. Winterfell-3 was temporarily plugged and abandoned during the first quarter of 2025 while the partnership evaluated options to restore production from the Winterfell-3 fault block. During the second quarter of 2025, the partnership drilled the Winterfell-4 well to test a separate fault block and define the eastern extent of the Winterfell reservoir area. The Winterfell-4 well was abandoned in September 2025 by the operator due to challenges during 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.

In February 2026, Kosmos entered into a strategic alliance with Shell, exchanging interests in five exploration blocks in the Norphlet trend. Shell and Kosmos now have alignment over ten blocks in the Gulf of America to explore multiple prospects, including Trailblazer. Drilling of Trailblazer is planned for 2027 with Kosmos designated as development operator.

Equatorial Guinea

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 for upfront cash consideration of $180 million, subject to certain adjustments, and future contingent consideration of up to $39.5 million, comprising $12.5 million linked to production performance at the Ceiba field and $9 million payable in each of 2027, 2028 and 2029, which are subject to certain oil price and production thresholds. 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.

Production in Equatorial Guinea averaged approximately 20,400 Bopd gross (7,200 Bopd net) for the year ended December 31, 2025, impacted by multiple flow pump (MPP) mechanical failures at Ceiba during the second quarter of 2025. One pump is currently back online with another pump expected to be online in the first quarter of 2026.

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

In October 2025, we submitted a formal notice to the Ministry of Hydrocarbons and Mining Development that we are electing to exit Block S offshore Equatorial Guinea.

In February 2026, we notified our partners that we are withdrawing from Block EG-01.

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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.

Mauritania and Senegal

Greater Tortue Ahmeyim Project

Production in Mauritania and Senegal averaged approximately 35,000 Boepd gross (8,500 Boepd net) for the full year ended December 31, 2025, as production from the Greater Tortue Ahmeyim (GTA) liquefied natural gas (LNG) project ramped up. The GTA LNG project achieved first gas production from the subsea system to the FPSO on December 31, 2024. First LNG was achieved in February 2025 and the first gross LNG cargo was successfully exported in April 2025. Eighteen and a half gross LNG cargos and one condensate cargo were lifted in 2025. The 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. Production averaged approximately 58,200 Boepd gross (14,200 Boepd net) for the three months ended December 31, 2025. 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.

Yakaar and Teranga Discoveries

On Yakaar-Teranga, we are working with PETROSEN to withdraw from the block given we have not been able to attract a suitable partner and agree a commercially attractive development concept with the government of Senegal. Accordingly, during the year ended December 31, 2025, we wrote off $143.7 million of unproved property costs associated with the Yakaar and Teranga discoveries, which were largely incurred before 2020.

Sao Tome and Principe

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

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Results of Operations

All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal, the Gulf of America. Certain operating results and statistics for the years ended December 31, 2025, 2024 and 2023 are included in the following tables. For a discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024.

Years ended December 31,

(In thousands, except per volume data)

Sales volumes:

Oil (MBbl)

Gas (MMcf)

NGL (MBbl)

Total (MBoe)

Total (Boepd)

Revenues:

Oil sales

Gas sales

NGL sales

Total revenues

Average oil sales price per Bbl

Average gas sales price per Mcf

Average NGL sales price per Bbl

Average total sales price per Boe

Costs:

Oil and gas production, excluding workovers

Oil and gas production, workovers

Total oil and gas production costs

Depletion, depreciation and amortization

Average cost per Boe:

Oil and gas production, excluding workovers

Oil and gas production, workovers

Total oil and gas production costs

Depletion, depreciation and amortization

Total oil and gas production costs, depletion, depreciation and amortization

(1) Substantially all NGLs and natural gas sales in Ghana and the Gulf of America are associated production from our oil wells and, therefore, production costs metrics are presented under a common unit of measure. In Mauritania and Senegal, all condensate sales and LNG sales are associated production from our gas wells. 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. Production costs per Bcf in Mauritania and Senegal was $14.68 for the year ended December 31, 2025. Mauritania and Senegal LNG sales are presented as gas sales in the table.

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The discussion of the results of operations and the period‑to‑period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.

Year Ended December 31, 2025 vs. 2024

Years Ended December 31,

Increase

(Decrease)

(In thousands)

Revenues and other income:

Oil and gas revenue

Gain on sale of assets

Other income, net

Total revenues and other income

Costs and expenses:

Oil and gas production

Exploration expenses

General and administrative

Depletion, depreciation and amortization

Impairment of long-lived assets

Interest and other financing costs, net

Derivatives, net

Other expenses, net

Total costs and expenses

Income (loss) before income taxes

Income tax expense

Net income (loss)

Oil and gas revenue. Oil and gas revenue decreased by $387.0 million during the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily as a result of lower average realized oil and gas prices and lower production resulting in lower sales volume at Jubilee and Equatorial Guinea partially offset by increased sales volumes in Mauritania and Senegal with LNG and condensate cargo sales beginning in 2025. We sold 22,414 MBoe at an average realized price per barrel of oil equivalent of $57.48 in 2025 and 23,507 MBoe at an average realized price per barrel of oil equivalent of $71.27 in 2024.

Oil and gas production. Oil and gas production costs increased by $178.4 million during the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily as a result of a full year of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal.

Exploration expenses. Exploration expenses increased by $103.7 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of approximately $58.5 million of exploration expense related to the Winterfell-4 step out well which was plugged and abandoned during the third quarter of 2025 and approximately $143.7 million of previously capitalized costs related to the Yakaar and Teranga discoveries incurred under the Cayar Offshore Profound Block license that were written off to exploration expense for the year ended December 31, 2025 compared to approximately $28.0 million related to the S-6 “Akeng Deep” ILX prospect in Block S offshore Equatorial Guinea which encountered sub-commercial quantities of hydrocarbons and was plugged and abandoned in the fourth quarter of 2024 and approximately $37.2 million of previously capitalized costs related to the Asam discovery in Block S offshore Equatorial Guinea that were written off to exploration expense for the year ended December 31, 2024, partially offset by decreased seismic, geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $100.0 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of the ramp-up of LNG production resulting in first LNG and condensate sales in 2025 at the GTA Phase 1 project in Mauritania and Senegal and higher depletion rates per Boe across our portfolio partially offset by lower sales volumes at Jubilee and Equatorial Guinea.

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Impairment of long-lived assets. As a result of negative proved oil and gas reserves revisions in certain of our Gulf of America fields, primarily Winterfell, we recorded a proved property impairment charge of $177.6 million during the year ended December 31, 2025.

Interest and other financing costs, net. Interest and other financing costs, net increased by $134.8 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of decreased capitalized interest for the year ended December 31, 2025 related to the GTA Phase 1 project post first gas production in December 2024 partially offset by a $25.2 million loss on debt modifications and extinguishments primarily related to the amendment and restatement of the Facility during the second quarter of 2024.

Income tax expense (benefit). For the years ended December 31, 2025 and 2024, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rate applicable to our Ghanaian operations and the 25% statutory tax rate applicable to our Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate, or jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

Liquidity and Capital Resources

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

Oil prices are historically volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This oil price volatility could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program and our current liquidity position is expected to support our capital program for 2026.

As such, our 2026 capital budget is based on our exploitation plans for our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our development activities in the Gulf of America and in Mauritania and Senegal.

Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation, exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil, natural gas, and LNG and our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.

As of December 31, 2025, borrowings under the Facility totaled approximately $1.2 billion and the undrawn availability under the facility was $150.0 million. In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion.

Leverage was elevated in 2025 given lower oil prices and the impact of operating costs during ramp-up of the GTA Phase 1 project combined with lower Company production. As a result, in July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment made this covenant less restrictive for the two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x respectively, and returned to the originally agreed upon ratio of 3.50x for assessment dates thereafter. In February 2026, we further amended the debt cover ratio calculation through September 2026. This most recent amendment makes the covenant less restrictive for the two scheduled financial covenant assessment dates in March 2026 and September 2026, up to a maximum of 4.5x and 4.25x respectively, and for purposes of the financial covenant assessment date in March 2026, the calculation will be made excluding the Company’s Mauritania and Senegal business unit. The debt cover ratio returns to the originally agreed upon ratio of 3.5x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower potential oil prices and the impact of operating costs during ramp-up of the GTA Phase 1 project on our results of operations.

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Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2025, 2024 and 2023:

Years Ended December 31,

(In thousands)

Sources of cash, cash equivalents and restricted cash:

Net cash provided by operating activities

Net proceeds from issuance of senior notes

Borrowings under long-term debt

Uses of cash, cash equivalents and restricted cash:

Oil and gas assets

Notes receivable and other investing activities

Payments on long-term debt

Purchase of capped call transactions

Repurchase and redemption of senior notes

Dividends

Other financing costs

Increase (decrease) in cash, cash equivalents and restricted cash

Net cash provided by operating activities. Net cash provided by operating activities in 2025 was $134.0 million compared with net cash provided by operating activities of $678.2 million in 2024 and $765.2 million in 2023, respectively. The decrease in cash provided by operating activities in the year ended December 31, 2025 when compared to the same period in 2024 is primarily a result of lower average realized oil and gas prices, lower sales volumes in Ghana and Equatorial Guinea, higher oil and gas production costs related to the ramp-up of LNG production at the GTA Phase 1, partially offset by increased sales volumes in Mauritania and Senegal with LNG and condensate cargo sales beginning in 2025 and lower workover expense in Equatorial Guinea. The decrease in cash provided by operating activities in the year ended December 31, 2024 when compared to the same period in 2023 is primarily a result of increased oil and gas production costs for the year ended December 31, 2024 as a result of pre-production operating costs associated with the GTA Phase 1 project, planned workovers in the Gulf of America business unit, and increased production costs in Equatorial Guinea, together with lower average realized oil prices, offset by changes in working capital.

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

Years Ended December 31,

(In thousands)

Outstanding debt principal balances:

Facility(2)

7.125% Senior Notes(1)

7.750% Senior Notes(2)

7.500% Senior Notes

8.750% Senior Notes

3.125% Convertible Senior Notes

GoA Term Loan Facility(1)

Total long-term debt

Cash and cash equivalents

Total restricted cash(3)

Net debt

Availability under the Facility(2)

Availability under the GoA Term Loan Facility(1)

Available borrowings plus cash and cash equivalents

(1) As of December 31, 2025, the undrawn availability under the GoA Term Loan Facility was $100 million, subject to certain conditions on borrowing. In January 2026, we received net proceeds of $98.5 million from funding the second tranche after deducting fees and other expenses. The net proceeds were used, together with cash on hand, to fund the redemption of the remaining $100.0 million of the 7.125% Senior Notes due 2026.

(2) As of December 31, 2025, the undrawn availability under the Facility was $150.0 million, subject to certain conditions on borrowing. In January 2026, the Company issued $350 million of 11.250% Senior Secured Bonds due in 2031 in the Nordic market. In February 2026, Kosmos used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of the 7.750% Senior Notes due 2027 and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.

(3) When our debt cover ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our debt cover ratio was 2.54x. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance through 2025. As of December 31, 2025, our debt cover ratio was 5.49x. Our next financial covenant assessment date is March 31, 2026, after which date we will be required to restrict approximately $50.0 million in cash as required under the terms of the Facility unless otherwise waived by the lenders

Capital Expenditures and Investments

We expect to incur capital costs as we:

• drill additional infill wells in Ghana and the Gulf of America;

• advance development efforts in the Gulf of America and in Mauritania and Senegal; and

• execute facilities integrity activities in Equatorial Guinea.

We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our paying interests in our operations including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third‑party projects, the availability of suitable equipment and qualified personnel and our cash flows from operations. We also evaluate potential corporate and asset acquisition and divestment opportunities, which may impact our budget assumptions. These assumptions are inherently subject to significant business, political, economic, regulatory, health, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our assumptions proves to be incorrect, or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell assets, equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could

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result in dilution to our shareholders. The incurrence of additional indebtedness could result in increased fixed obligations and additional covenants that could restrict our operations.

2026 Capital Program

We estimate we will spend approximately $350 million of capital for the year ending December 31, 2026, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

• Approximately $275 million related to maintenance activities across our Ghana and Gulf of America assets, including infill development drilling and TEN FPSO purchase payments;

• Approximately $60 million related to progressing our development programs in the Gulf of America and in Mauritania and Senegal; and

• Approximately $15 million related to facilities integrity activities in Equatorial Guinea.

The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our exploitation and drilling results among other factors. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil, natural gas, and LNG and the prices we receive from the sale of oil, natural gas and LNG, and our ability to effectively hedge future production volumes, the success of our multi-faceted infrastructure-led exploration, appraisal, and development drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners’ alignment with respect to capital plans, and the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.

Significant Sources of Capital

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Jubilee and TEN Fields in Ghana and the Ceiba Field and Okume Complex in Equatorial Guinea.

In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion. As of December 31, 2025, borrowings under the Facility totaled $1.2 billion and the undrawn availability under the facility was $150.0 million. In February 2026, the Company used a portion of the net proceeds from the Nordic bond offering to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on April 1, 2027, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of December 31, 2029. As of December 31, 2025, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. We were in compliance with the financial covenants contained in the Facility, as amended, as of September 30, 2025 (the most recent assessment date). The Facility contains customary cross default provisions.

The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition, we periodically review our banking

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and financing relationships, considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.

Senior Notes

We have three series of senior notes outstanding, which we collectively refer to as the “Senior Notes.” Our 7.750% Senior Notes have an outstanding balance of $350.0 million as of December 31, 2025 and mature on May 1, 2027. In February 2026, we used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of the 7.750% Senior Notes. Interest is payable on the 7.750% Senior Notes each May 1 and November 1. Our 7.500% Senior Notes have an outstanding balance of approximately $400.3 million on December 31, 2025 and mature on March 1, 2028. Interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 8.750% Senior Notes have an outstanding balance of $500.0 million on December 31, 2025 and mature on October 1, 2031. Interest is payable on the 8.750% Senior Notes each April 1 and October 1.

The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equally in right of payment with all of its existing and future senior indebtedness (including the 3.125% Convertible Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.

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3.125% Convertible Senior Notes due 2030

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

The 3.125% Convertible Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including the Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility, to the extent of the value of the assets securing such indebtedness). The 3.125% Convertible Senior Notes are guaranteed on a senior, unsecured basis by certain of our existing subsidiaries that guarantee on a senior basis the Senior Notes, and, in certain circumstances, certain of our existing future subsidiaries. The 3.125% Convertible Senior Notes are guaranteed on a subordinated, unsecured basis by certain of our existing subsidiaries that borrow under or guarantee the Facility and guarantee on a subordinated basis the Senior Notes, and, in certain circumstances, certain of our existing or future subsidiaries.

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

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

GoA Term Loan Facility

On September 24, 2025, the Company entered into a senior secured term loan credit agreement secured by first priority liens on all the Company’s Gulf of America assets (as defined in the GoA Term Loan credit agreement). The GoA Term Loan Facility is a four-year term loan structured in two tranches, with the first tranche an aggregate principal amount of $150.0 million, which was funded in October 2025, and a second tranche of an additional $100.0 million, which was funded in January 2026. The net proceeds were used, together with cash on hand, to fund the redemption of the $250.0 million in aggregate, of the 7.125% Senior Notes due 2026.

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

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

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

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

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

GTA Nordic Bonds

In January 2026, we issued one series of senior secured GTA Nordic bonds totaling $350.0 million. Our 11.250% senior secured GTA Nordic bonds mature in January 2031, unless earlier redeemed or repurchased. Interest is payable semi-annually in arrears each July 29 and January 29, commencing July 29, 2026.

The GTA Nordic bonds were issued by Kosmos Energy GTA Holdings, a wholly-owned subsidiary of Kosmos Energy Ltd., and are fully and unconditionally guaranteed by the Company, as well as the Company’s wholly-owned subsidiaries, Kosmos Energy Tortue Finance, Kosmos Energy Senegal, Kosmos Energy Investments Senegal Limited and Kosmos Energy Mauritania. The GTA Nordic bonds are also guaranteed on an unsecured basis by certain of the Company’s subsidiaries that also guarantee the Company’s existing senior unsecured notes.

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Contractual Obligations

The following table presents maturities by expected debt maturity dates, the weighted-average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the instrument’s estimated fair value. Weighted‑average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs.

Years Ending December 31,

Asset

(Liability)

Fair Value at

December 31,

Thereafter

Total

(In thousands, except percentages)

Fixed rate debt:

7.125% Senior Notes(5)

7.750% Senior Notes(6)

7.500% Senior Notes

8.750% Senior Notes

3.125% Convertible Senior Notes

Variable rate debt:

Weighted average interest rate

Facility(1)(6)

GoA Term Loan Facility(5)

Total principal debt repayments

Interest & commitment fees on long-term debt

Operating leases(2)

Purchase obligations(3)

Decommissioning trust funds(4)

Firm transportation commitments

(1) The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of December 31, 2025. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

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

(3) Represents gross contractual obligations to execute planned future capital projects. Other joint owners in the properties operated by Kosmos will be billed for their working interest share of such costs. Does not include our share of operator’s purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts. The Company's liabilities for asset retirement obligations associated with the dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 11—Asset Retirement Obligations of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding these liabilities.

(4) In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total remaining commitment to be approximately $122.6 million as of December 31, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated fifteen year period based on the expiration date of the WCTP and DT Petroleum Agreements, which has now been extended to 2040. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.

(5) In January 2026, we used net proceeds of $98.5 million from the funding of the second tranche of the GoA Term Loan Facility, together with cash on hand, to fund the redemption of the remaining $100.0 million of the 7.125% Senior Notes due 2026.

(6) In January 2026, the Company issued $350.0 million of 11.250% Senior Secured Bonds due 2031 in the Nordic market. In February 2026, Kosmos used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of the 7.750% Senior Notes due 2027 and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.

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As of December 31, 2025, we have a commitment to drill one development well in Equatorial Guinea. As part of the license extensions of WCTP and DT Petroleum Agreements in Ghana, we have a commitment to drill a minimum of ten development wells under the amended Jubilee plan of development.

Once the Tortue Phase 1 SPA Commercial Operations Date was achieved in February 2026, we have a commitment to our buyer under the Tortue Phase 1 SPA, BP Gas Marketing Limited, to deliver our proportionate share of a minimum annual contract quantity of LNG of 127,951,000 MMBtu, which is equivalent to approximately 2.45 million tonnes per annum, subject to certain downward adjustments by the sellers. Under certain circumstances, in the event the annual quantities provided are lower than the minimum annual contract quantity, Kosmos may be obligated to credit or pay a portion of the Contract Price to BP Gas Marketing Limited for the shortfall volumes.

In February 2026, the TEN partnership executed the final Sale and Purchase Agreement to acquire the TEN FPSO from MODEC, Inc. at the end of its current lease in 2027 for a gross purchase price of $205.0 million. We have a commitment to Tullow for our proportionate share of the gross purchase price.

Critical Accounting Policies

This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities as of the date the financial statements are available to be issued. These estimates could change materially if different information or assumptions were used. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies.” We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

Revenue Recognition. We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2025 and 2024, we had no oil and gas imbalances recorded in our consolidated financial statements.

Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a derivative that is separated from the host contract for accounting purposes. The host contract is the receivable from sales at the spot price on the date of sale. The derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.

Exploration and Development Costs. We follow the successful efforts method of accounting for our oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense.

Income Taxes. We account for income taxes as required by the ASC 740—Income Taxes (“ASC 740”). We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of changes in tax laws or tax rates, tax credits, and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we

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would not expect to recover, which would result in no benefit for the deferred tax amounts. As of December 31, 2025 and 2024, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

ASC 740 provides a more‑likely‑than‑not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following:

• the status of our operations in the particular taxing jurisdiction, including whether we have commenced production from a commercial discovery;

• whether a commercial discovery has resulted in significant proved reserves that have been independently verified;

• the amounts and history of taxable income or losses in a particular jurisdiction;

• projections of future income, including the sensitivity of such projections to changes in production volumes and prices;

• the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward in a jurisdiction; and

• the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets.

Estimates of Proved Oil and Gas Reserves. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Proved reserve quantities and future cash flows are estimated by independent petroleum engineering consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:

• the engineering and geological interpretation of available data;

• estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;

• the accuracy of various mandated economic assumptions; and

• the judgments of the persons preparing the estimates.

Asset Retirement Obligations. We account for asset retirement obligations as required by ASC 410 — Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition or in service date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations. Estimating the future restoration and removal costs requires management to make estimates and judgments because most of the removal obligations are many years in the future and the regulations in some countries that we operate often have vague descriptions of what constitutes removal. Additionally, asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance.

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Impairment of Long‑lived Assets.  We review our long‑lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360 — Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long‑lived asset is not recoverable and exceeds its fair value. The carrying amount of a long‑lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. Assets to be disposed of and assets not expected to provide any future service potential to us are recorded at the lower of carrying amount or fair value. Oil and gas properties are grouped in accordance with ASC 932 — Extractive Activities-Oil and Gas. The basis for grouping is a reasonable aggregation of properties typically by field or by logical grouping of assets with significant shared infrastructure.

For long-lived assets whereby the carrying value exceeds the estimated future undiscounted cash flows, the carrying amount is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 — Fair Value Measurement. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted-average cost of capital. Although we base the fair value estimate of each asset group on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserve quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.

We believe the assumptions used in our analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows and fair value. Kosmos has consistently used an average of third-party industry forecasts to determine our pricing assumptions. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation.

Acquisition Accounting. The purchase price in an acquisition (business combination or asset acquisition) is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the deal announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired, and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.

New Accounting Pronouncements

See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies” for a discussion of recent accounting pronouncements.

Item 7A.  Qualitative and Quantitative Disclosures About Market Risk

The primary objective of the following information is to provide forward‑looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward‑looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market‑risk sensitive instruments for purposes other than to speculate.

We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data—Note 2—Accounting Policies, Note 9—Derivative Financial Instruments and Note 10—Fair Value Measurements” for a description of the accounting procedures we follow relative to our derivative financial instruments.

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The following table reconciles the changes that occurred in fair values of our open derivative contracts during the year ended December 31, 2025:

Derivative Contracts Assets (Liabilities)

Commodities

Interest Rates

Total

(In thousands)

Fair value of contracts outstanding as of December 31, 2024

Changes in contract fair value

Contract maturities

Fair value of contracts outstanding as of December 31, 2025

Commodity Price Risk

The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Substantially all of our oil sales are indexed against Dated Brent and Heavy Louisiana Sweet. Oil prices during 2025 ranged between $60.20 and $83.06 per Bbl for Dated Brent, with Heavy Louisiana Sweet experiencing similar volatility during 2025.

Commodity Derivative Instruments

We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of collars, put options, call options and swaps. In regards to our obligations under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase. In addition, a reduction in our ability to access credit could reduce our ability to implement derivative contracts on commercially reasonable terms.

Commodity Price Sensitivity

The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of December 31, 2025. Volumes and weighted average prices are net of any offsetting derivatives entered into.

Weighted Average Price per Bbl

Term

Type of Contract

Index

MBbl

Net Deferred Premium Payable/(Receivable)

Swap

Sold Put

Floor

Ceiling

Asset (Liability) Fair Value at December 31, 2025(1)

Jan - Jun

Two-way collars

Dated Brent

Jan - Dec

Three-way collars

Dated Brent

Jan - Jun

Swaps(1)

Dated Brent

Jan - Dec

Swaps(1)

Dated Brent

Jan - Dec

Swaps(1)

Dated Brent

Jan - Dec

Swaps(1)

NYMEX WTI

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

In January 2026, we entered into Dated Brent three-way collar contracts for 2.0 MMBbl from January 2027 through December 2027 with a weighted average sold put price of $47.50 per barrel, a floor price of $60.00 per barrel and a ceiling price of $75.00 per barrel.

At December 31, 2025, our open commodity derivative instruments were in a net asset position of $50.5 million. As of December 31, 2025, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre‑tax earnings by approximately $36.7 million. Similarly, a hypothetical 10% price decrease would increase future pre‑tax earnings by approximately $36.2 million.

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Interest Rate Sensitivity

Changes in market interest rates affect the amount of interest we pay on certain of our borrowings. Outstanding borrowings under the Facility and GoA Term Loan Facility as of December 31, 2025 totaled $1.35 billion. The weighted average interest rate on this indebtedness was approximately 7.7%, and is subject to variable interest rates, which expose us to the risk of earnings or cash flow loss due to potential increases in market interest rates. If the floating market rate increased 10% at this level of floating rate debt, we would pay an estimated additional $4.9 million of interest expense per year on the Facility and GoA Term Loan Facility. The commitment fees on the undrawn availability under the Facility are not subject to changes in interest rates. All of our other long-term indebtedness is fixed rate and does not expose us to the risk of cash flow loss due to changes in market interest rates. Additionally, a change in the market interest rates could impact interest costs associated with future debt issuances or any future borrowings and future payments associated with the Tortue FPSO arrangement.

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