KOS 10-K & 10-Q changes, risk factors and insider trading

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

•Our commercial debt facilityfacility, 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;

Under certain petroleum contracts, we have work commitments to perform exploration and other related activities. Failure to do so may result in our loss of the licenses. As of December 31, 2024,2025, we have unfulfilleda drillingcommitment obligations forto 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 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 redeterminationredetermination. onceFollowing sufficient development work has been completed in the unit. Thean initial redetermination process was completed on October 14, 2011. As a result of the initial redetermination process,2011, the tract participation was determined to be 54.4% 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, which owned a participating interestCompany in theOctober WCTP Block2021 and DT Block, our Unit Interest (participating interest in the Jubilee Unit) increased from 24.1% to 42.1%. Following the completion of the subsequent pre-emption by Tullow in March of 2022, Kosmos’ interest in the Jubilee Unit Area decreasednow fromstands 42.1% toat 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.

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. We granted the Government of Ghana the first 200 Bcf of natural gas exported from the Jubilee Field to shore at zero cost. As of January 1, 2023, the Jubilee partners had fulfilled this commitment. During 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas to the Government of Ghana through May 2024. This interim gas sales agreement was subsequently extended to November 2025 whileat 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 continue on-going discussions with theand Government of Ghana regardinghave aapproved long-terman future gas sales agreement. If the interimamended gas sales agreement isat nota price of $2.50 per MMBtu through the extended againexpiration ordate aof long-term2040 gasfor salesthe agreementWCTP inand GhanaDT is not approved, we may not be able to commercialize our natural gas resources in Jubilee.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 plancurrently toonly export the majority of our gas resource to the LNG market.market, However,we thatalso intend to utilize existing facilities for domestic gas delivery. This plan is contingent on making additional final investment decisions on oursigning gas discoveriessales agreements for domestic gas and constructing the necessary infrastructure to produce, liquefy and transport the gas to thedomestic market.onshore markets being constructed. Additionally, such plans are contingent upon receipt of required partner and government approvals.

Our ability to market our oil and natural gas production will dependdepends 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 continuingcontinued access to drilling rigs and construction vessels suitable for the environment in which we operate.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 rigsrigs, vessels or vesselsother 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.

Furthermore, the marketability of expected oiloil, natural gas, and natural gasLNG 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 gasgas, 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 andoil, 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.

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

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

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,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:

•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;

Significant outbreaks of contagious diseases,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 diseasedisease, 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.

For example, an epidemic of the Ebola virus disease occurred in parts of West Africa in 2014 and continued through 2015. A substantial number of deaths were reported by the World Health Organization (“WHO”) in West Africa, and the WHO declared it a global health emergency. Likewise, the global spread of the COVID-19 pandemic resulted in travel restrictions, “shelter-in-place” and various quarantine measures and other governmental actions taken to inhibit its spread and created significant volatility, uncertainty and economic disruption in the markets in which we operate, which affected our business and operations and those of our suppliers, contractors and partners. It is impossible to predict the effect and potential spread of new outbreaks of the Ebola virus or other viruses in West Africa and surrounding areas. Should another Ebola or other virus outbreak occur, including to the countries in which we operate, or not be satisfactorily contained, our exploration, development and production plans for our operations could be delayed, or interrupted after commencement. Any changes to these operations could significantly increase costs of operations. 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.

Our commercial debt facilityfacility, 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 facilityfacility, 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:

•the granting of liens, other than liens created pursuant to the commercial debt facilityfacility, 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;

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

Our commercial debt facilityfacility, requiresthe 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 facilityfacility, 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 facilityfacility, 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, 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 facilityfacility, 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.

At December 31, 2024,2025, we had $900.0$1,200.0 million outstanding and $450.0$150.0 million of committed undrawn available capacity under our commercial debt facility. As of December 31, 2024,2025, we had $1.9$1.8 billion principal amount of Senior Notes and Convertible Senior Notes outstanding.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 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.

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, as is the case in Ghana, where the GRA has disputed certain tax deductions we had claimed in prior fiscal years’ Ghanaian tax returns as non‑allowable under the terms of the Ghanaian Petroleum Income Tax Law, as well as non‑payment of certain transactional taxes, contractual fiscal obligations and other payments. We have faced, and continue to face, similar tax related disputes with the Senegal, Mauritania, and Equatorial Guinea Tax Administrations.activities.

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 revisesrevised requirements for well design, well control, casing, cementing, real-time monitoring (RTM), and subsea containment. These revisions modifymodified 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. ForSince a discussion of recent drilling and climate change executive orders signed by former President Biden and the potential impactadoption of the new2019 Trumprule, AdministrationBSEE onhas theseadopted orders,additional seewell thecontrol riskrequirements factorand earliercontinues into thisevaluate 10-Kand titledimplement “Ourfurther business,regulatory initiatives applicable to offshore oil and gas operations andthrough financialamendments, condition may be directlyguidance and indirectlyongoing adverselyor affectedanticipated by political, economic and environmental circumstances, and changes in laws and regulations, in the countries and regions in which we operate.”rulemakings.

In addition to the array of new or revised safety, permitting and certification requirements developed and implemented by the DOI in the past few years, there have been a variety of proposals to change existing laws and regulations that could affect offshore development and production, such as, for example, a proposal to significantly increase the minimum financial responsibility demonstration required under the Oil Pollution Act of 1990. To the extent the existing regulatory initiatives implemented and pursued overin the past fewrecent years or any future restrictions, whether through legislative or regulatory means or increased or broadened permitting and enforcement programs, foster uncertaintiesuncertainties, delays or delaysincreased 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, moratoria on new leasesrestrict or delay leasing or permitting or that otherwise adversely affectingaffect our offshore activities could result in increased costs, limit our operations and adversely impact our future financial results.

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 hasonce indicatedagain that he intends to withdrawwithdrew 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 repotreport 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, in March 2024, the SEC finalized rules requiring disclosure of a range of climate change-related information, including, amongnumerous other things, companies’ climate change risk management; material climate-related financial risks; and disclosureGHG emissions laws, regulations or rules have been proposed or are in various stages of material Scope 1review and/or Scope 2 emissions. While implementation of the rules could be costly and time consuming, litigation challenging the rules has commenced, and the SEC has stayed the rules pending this litigation; in addition, President Trump criticized these rules during his campaign, and it is expected that his administration could take steps to undo them.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. For a discussion of environmental and climate change executive orders signed by former President Biden and the potential impact of the Trump Administration on these orders, see the risk factor earlier in this 10-K titled “Our business, operations and financial condition may be directly and indirectly adversely affected by political, economic and environmental circumstances, and changes in laws and regulations, in the countries and regions in which we operate.”

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 in (for example, by way of acquiring equity interests in, participating as a joint venture partner with, acquiring the assets of, or entering into certain commercial transactions with) or that we acquire.

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.

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, SenegalSenegal, and the Gulf of America (formerly the U.S. Gulf of Mexico).America. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success.

Production in Equatorial Guinea averaged approximately 25,00020,400 Bopd gross (8,7007,200 Bopd net) for the year ended December 31, 2024.2025, 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 DecemberOctober 2024,2025, we received approval from the Ministry of Hydrocarbons and Mining Development for a twelve month extension to December 20252026 for the current exploration phase of Block EG-24.

In DecemberOctober 2024,2025, we submitted a formal notice to the Ministry of Hydrocarbons and Mining Development that we are electing to exit Block 21.S offshore Equatorial Guinea.

In AprilMay 2024,2025, we received approval for a twelve month extension to May 20252026 for the current exploration phase for Block 5 offshore Sao Tome and Principe.

All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal, the Gulf of America, Equatorial Guinea, Mauritania and Senegal.America. Certain operating results and statistics for the years ended December 31, 2024,2025, 20232024 and 20222023 are included in the following tables. For a discussion of the year ended December 31, 20232024 compared to the year ended December 31, 2022,2023, 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, 2023.2024.

Oil and gas revenue. Oil and gas revenue decreased by $26.3$387.0 million during the year ended December 31, 20242025 as compared to the year ended December 31, 20232024 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 natural gas sales volumes in GhanaMauritania forand theSenegal yearwith endedLNG Decemberand 31,condensate 2024.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 and 23,057 MBoe at an average realized price per barrel of oil equivalent of $73.80 in 2023.2024.

Oil and gas production. Oil and gas production costs increased by $140.4$178.4 million during the year ended December 31, 20242025 as compared to the year ended December 31, 20232024 primarily as a result of pre-productiona full year of operating costs associated with Phasethe 1ramp-up of LNG production at the GTA project,Phase planned1 workoversproject in the Gulf of America business unitMauritania and increased production costs in Equatorial Guinea.Senegal.

Exploration expenses. Exploration expenses increased by $77.6$103.7 million during the year ended December 31, 2024,2025, as compared to the year ended December 31, 20232024 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.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 $11.8$100.0 million during the year ended December 31, 2024,2025, as compared to the year ended December 31, 20232024 due to a higher depletion rate per boe in the Gulf of America and Equatorial Guinea business unitsprimarily as a result of the increasedramp-up costof basisLNG relatedproduction toresulting in first LNG and condensate sales in 2025 at the respectiveGTA developmentPhase activities1 project in 2024,Mauritania and Senegal and higher depletion rates per Boe across our portfolio partially offset by lower depletionsales involumes theat currentJubilee yearand inEquatorial our TEN Fields due to the impairment loss recorded during the year ended December 31, 2024.Guinea.

Interest and other financing costs, net. Interest and other financing costs, net decreasedincreased by $7.3$134.8 million during the year ended December 31, 2024,2025, as compared to the year ended December 31, 20232024 primarily as a result of increaseddecreased capitalized interest for the year ended December 31, 2025 related to the Greater Tortue AhmeyimGTA Phase 1 project post first gas production in December 2024 partially offset by increased interest expenses related to higher interest rates anda $25.2 million loss on debt modifications and extinguishments for the year ended December 31, 2024 primarily related to the amendment and restatement of the Facility during the second quarter of 2024 and the repurchase of aggregate principal amounts of the 7.125% Senior Notes, the 7.750% Senior Notes, and the 7.500% Senior Notes during the third quarter of 2024.

Income tax expense (benefit). For the years ended December 31, 20242025 and 2023,2024, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax ratesrate applicable to our Ghanaian operations and the 25% statutory tax rate applicable to our Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate, or jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

As such, our 20252026 capital budget is based on our exploitation plans for our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our appraisal and development activities in the Gulf of America,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 oiloil, natural gas, and gas,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.

Net cash provided by operating activities. Net cash provided by operating activities in 20242025 was $678.2$134.0 million compared with net cash provided by operating activities of $678.2 million in 2024 and $765.2 million in 20232023, 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 $1.1gas billionprices, lower sales volumes in 2022,Ghana respectively.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 of the GTA project, planned workovers in the Gulf of America business unitunit, and increased production costs in Equatorial Guinea, together with lower average realized oil prices, offset by changes in working capital. The decrease in cash provided by operating activities in the year ended December 31, 2023 when compared to the same period in 2022 is primarily a result of lower average realized oil prices.

(13)When our netdebt leveragecover ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our netdebt leveragecover ratio was 2.54x,2.54x. partiallyDuring duethe first quarter of 2025, the Facility lenders waived the requirement to pre-productionmaintain operatinga costsrestricted associatedcash withbalance thethrough Greater Tortue Ahmeyim Phase 1 project.2025. As of December 31, 2024,2025, weour expectdebt thecover paymentratio ofwas interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes to be approximately $66.0 million.5.49x. Our next financial covenant assessment date is March 31, 2025,2026, after which date we couldwill be required to restrict approximately $66.0$50.0 million in cash as required under the terms of the Facility unless otherwise waived by the lenders.lenders

•drill additional infill wells and execute exploitation and production activities in Ghana, Equatorial GuineaGhana and the Gulf of America;

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 operateoperate, we are advancing high-quality development opportunities,opportunities which have come from our exploration success.

In April 2026, during the Spring 2026 redetermination, the Company’s lending syndicate approved a borrowing base at approximately $1.25 billion for the Facility,Facility. and a further reduction to approximately $1.2 billion uponFollowing the closeclosing of the sale of all our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea.Guinea on June 16, 2026, the Company’s production assets in Equatorial Guinea are no longer included in the borrowing base amount, and, as agreed with the lending syndicate, the borrowing base has been reduced to approximately $1.2 billion.

Jubilee development drilling progressedcontinued into theprogress firstwith quartera total of 2026 bringing twofour producer wells successfully brought online during the firstyear through the end of July 2026. To complete this year’s development drilling campaign, the final producer well is expected online in the coming days and a water injector well is expected online around the end of the third quarter of 2026. The remaining development drilling campaign in 2026 is planned to include three additional producer wells and one additional water injector well.

Production from the Gulf of America averaged approximately 16,80014,300 Boepd net (~84%83% oil) for the firstsecond quarter of 2026.

At Winterfell, the partnership spud Winterfell-5 in April 2026. Winterfell-5 iswas designed as a twin well to Winterfell-3 andin is expectedorder to restore production from the Winterfell-3 fault block. The Winterfell-5 well was temporarily abandoned in July 2026 by the operator due to challenges experienced during drilling operations arising from issues with the production casing. The partnership is expectedcurrently onlineevaluating the cause of the casing issue in order to restore production from the thirdWinterfell-3 quarterfault of 2026.block. In April 2026, production from the Winterfell-2 was shut-in pending a future intervention. The Company maintains insurance coverage that it expects will offset a significant portion of any remediation costs that may be incurred to restore the Winterfell-2 well to normal operations.

On FebruaryJune 24,16, 2026, we entered into a Share Sale and Purchase Agreement with a subsidiary of Panoro Energy ASA forcompleted the sale of all our 40.4% participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea forto upfronta subsidiary of Panoro Energy ASA. Pursuant to the terms of the Sale and Purchase Agreement, Kosmos received final cash consideration of $180.0approximately $127.0 million, subjectbased toon the initial purchase price of $180.0 million reduced by certain purchase price adjustments andtotaling approximately $53.0 million. We are also entitled to future contingent consideration of up to $39.5 million, comprised of $12.5 million linked to future production performance at the Ceiba field and $9.0 million payable in each of the years 2027, 2028 and 2029, subject to certain Block G production and oil price thresholds. TheUpon transactionclosing, hasthe anCompany effectiverecognized datea gain on sale of Januaryassets 1,of 2025,approximately has$9.4 million, representing the excess of net proceeds received approval fromover the Governmentcarrying value of Equatorial Guinea and completion only remains subject to CEMAC customary approval. While we expect to close the transactiondisposal around the middle of 2026, there can be no assurances that closing will ultimately occur or that it may not be delayed.group. Operating results throughout this Form 10-Q continue to include the operating results of the EG business 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 unitthrough shouldthe therefore be read in lightdate of the ongoing transaction.sale.

Production in Mauritania and Senegal from GTA averaged approximately 69,80064,300 Boepd gross (17,00015,700 Boepd net) in the firstsecond quarter of 2026,2026. approximatelyNine 2.85gross millionLNG tonnescargos perand annum,one orgross 5%condensate abovecargo FLNGlifted nameplatein capacity.the second quarter of 2026.

All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America.America, including the results related to the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea through the date of sale in June 2026. See Note 3 - Acquisitions and Divestitures for additional information. Certain operating results and statistics for the three and six months ended MarchJune 31,30, 2026 and 2025 are included in the following tables:

(1)Substantially all NGLs and natural gas sales in Ghana and the Gulf of America are associated production from our oil wells and, therefore, production costs metrics are presented under a common unit of measure. In Mauritania and Senegal, all condensate sales and LNG sales are associated production from our gas wells and the first LNG cargo was successfully completed in April 2025. Oil and gas production costs related to LNG production at the GTA Phase 1 project were $55.3$65.8 million and $58.1$69.1 million for the three months ended MarchJune 31,30, 2026 and March2025, 31,respectively, and $121.2 million and $127.2 million for the six months ended June 30, 2026 and 2025, respectively. Production costs per Mcfe in Mauritania and Senegal was $6.80$6.98 and $23.13 for the three months ended MarchJune 31,30, 2026.2026 and 2025, respectively, and $6.89 and $36.95 for the six months ended June 30, 2026 and 2025. Mauritania and Senegal LNG sales are presented as gas sales in the table.

The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of MarchJune 31,30, 2026:

The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results.results including the results related to the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea through the date of sale in June 2026. See Note 3 - Acquisitions and Divestitures for additional information. The following discussion may not be indicative of future results.

Three months ended MarchJune 31,30, 2026 compared to three months ended MarchJune 31,30, 2025

Oil and gas revenue. Oil and gas revenue increased by $80.6$214.6 million during the three months ended MarchJune 31,30, 2026 as compared to the three months ended MarchJune 31,30, 2025 primarily as a result of higher production and sales volumes at Jubilee and GTA, with GTA producingand at 5% above FLNG nameplate capacity offset by lowerhigher average realized oil and gas prices.prices during the three months ended June 30, 2026, partially offset by lower sales volumes in Equatorial Guinea and in the Gulf of America business unit. We sold 6,6437,005 MBoe at an average realized price per barrel equivalent of $55.81$86.68 during the three months ended MarchJune 31,30, 2026 and 4,4456,663 MBoe at an average realized price per barrel equivalent of $65.27$58.93 during the three months ended MarchJune 31,30, 2025.

Oil and gas production. Oil and gas production costs decreased by $36.7$63.7 million during the three months ended MarchJune 31,30, 2026 as compared to the three months ended MarchJune 31,30, 20252025. Oil and gas production costs are lower in 2026 across all of our business units primarily as a result of lower routine operating costs acrossin all of our business unitsGhana and decreased workover expense in our Gulf of America business unit.GTA.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased by $0.8$30.8 million during the three months ended MarchJune 31,30, 2026, as compared with the three months ended MarchJune 31,30, 2025 primarily as a result of lower depletion rates per boeBoe acrossat ourJubilee portfolioand in the Gulf of America business unit and no depletion recorded on the Equatorial Guinea assets sold during the quarter, partially offset by higher sales volumes at Jubilee and GTA.

Derivatives, net. During the three months ended MarchJune 31,30, 2026 and 2025, we recorded a lossgain of $252.0$51.8 million and a lossgain of $6.7$21.6 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.

Income tax expense. For the three months ended MarchJune 31,30, 2026 and 2025, changes to our effective tax rates are driven by which tax jurisdictions our income (loss) before income taxes is generated. The jurisdictions in which we operate have statutory tax rates ranging from 0% to 35%.

As such, our 2026 capital budget for the second half of 2026 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.

The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the threesix months ended MarchJune 31,30, 2026 and 2025:

Net cash provided by (used in) operating activities. Net cash provided by operating activities for the threesix months ended MarchJune 31,30, 2026 was $106.6$281.6 million compared with net cash usedprovided inby operating activities for the threesix months ended MarchJune 31,30, 2025 of $0.9$126.3 million. The increase in cash provided by operating activities in the threesix months ended MarchJune 31,30, 2026 when compared to the same period in 2025 is primarily a result of higher production and sales volumes at Jubilee and GTA, higher average realized oil and gas prices, lower routine oil and gas production costs across all of our business units and decreased workover expense in our Gulf of America business unit, partially offset by lower average realized oil and gas prices for the three months ended March 31, 2026.unit.

The following table presents our liquidity and financial position as of MarchJune 31,30, 2026 and December 31, 2025:

(1) When our debt cover ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance until the March 31, 2026 financial covenant test date. During the second quarter of 2026, the Facility lenders agreed to reduce the amount of the required restricted cash balance to three months of interest and fees until the September 30, 2026 financial covenant test date, after which the amount of the required restricted cash balance will be determined as usual. Our debt cover ratio for the most recent March 31, 2026 financial covenant test date exceeded 2.50x and the estimated restricted cash funding requirement is approximately $47.0$23.5 million. WeAs areof currentlyJune in30, discussions with the Facility lenders seeking approval to extend the prior waiver, but if no approval is granted then2026, we planhave tofunded startapproximately funding$23.5 million into the debt service reserve account in the second quarter, as required under the terms of the Facility.

(2) Excludes $80.1$73.2 million TEN FPSO finance lease liability. For purposes of the debt cover ratio calculation under the Facility, the finance lease liability is included in net debt.

For our 2026 capital expenditure budget,budget for the second half of 2026, we expect to incur capital costs as we:

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

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

•Approximately $275$290 million related to maintenance activities and infill development drilling across our producing Ghana and Gulf of America assets, including infill development drilling andthe TEN FPSO purchase payments;

•Approximately $60 million related to progressing our development programs in the Gulf of America and in Mauritania and Senegal; and includes first half 2026 integrity spend in Equatorial Guinea.

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. In April 2026 during the Spring 2026 redetermination, the Company’s lending syndicate approved a borrowing base at approximately $1.25 billion. The borrowing base amount iswas based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Company’s production assets in Ghana and Equatorial Guinea. Following the closing of the sale of all our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea on June 16, 2026, the Company’s production assets in Equatorial Guinea are no longer included in the borrowing base amount, and, as agreed with the lending syndicate, the borrowing base has been reduced to approximately $1.2 billion. As of MarchJune 31,30, 2026, borrowings under the Facility totaled approximately $1.0$0.8 billion and the undrawn availability under the Facility was $350.0approximately $440 million. Final maturity of the Facility is December 31, 2029.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on April 1, 2027, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of December 31, 2029. As of MarchJune 31,30, 2026, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets. Leverage was elevated in 2025 given lower oil prices and the impact of operation costs during the ramp-up of the GTA Phase 1 project combined with lower company production. As a result, in July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment made this covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returned to the originally agreed upon ratio of 3.50x for assessment dates thereafter. In February 2026, we further amended the debt cover ratio calculation through September 2026. This most recent amendment makes the covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.5x and 4.25x respectively, and for purposes of the financial covenant assessment date in March 2026, the calculation was made excluding the Company’s Mauritania and Senegal business unit. The debt cover ratio returns to the originally agreed upon ratio of 3.5x for assessment dates thereafter. The change was intended to align the covenant calculation with recent business operations, lower oil prices and the impact of operating costs during the ramp-up of the GTA Phase 1 project on our results of operations. The Facility contains customary cross default provisions.