Kosmos Energy Ltd

1. Organization

Kosmos Energy Ltd. changed our jurisdiction of incorporation from Bermuda to the State of Delaware in December 2018 as a holding company for Kosmos Energy Delaware Holdings, LLC, a Delaware limited liability company. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly-owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly-owned subsidiaries, unless the context indicates otherwise.

Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America (formerly the U.S. Gulf of Mexico). Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success. Kosmos is listed on the NYSE and LSE and is traded under the ticker symbol KOS.

Kosmos is engaged in a single line of business, which is the exploration, development, and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to operations infour geographic areas: Ghana, Equatorial Guinea, Mauritania/Senegal and the Gulf of America.

2. Accounting Policies

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Kosmos Energy Ltd. and its wholly-owned subsidiaries. They also include the Company’s share of the undivided interest in certain assets, liabilities, revenues and expenses.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. 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 could differ from these estimates.

Reclassifications

Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no significant impact on our reported net income, current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents includes demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. When our net leverage ratio exceeds 2.50 x, 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 nextsix-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 net leverage ratio was 2.54 x, partially due to pre-production operating costs associated with the GTA Phase 1 project. Our next financial covenant assessment date is March 31, 2025, after which date we could be required to restrict approximately $66.0 million in cash as required under the terms of the Facility unless otherwise waived by the lenders. As of December 31, 2023 our net leverage ratio was below 2.50 x.

Receivables

Our receivables consist of joint interest billings, oil and gas sales, related party and other receivables. Receivables from joint interest owners are stated at amounts due, net of any allowances for doubtful accounts. As required by ASU 2016-13, "Measurement of Credit Losses on Financial Instruments", we determine our allowance based on historical experience, current conditions and reasonable and supportable forecasts by considering the length of time past due, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things. We had an allowance for doubtful accounts of $13.6 million and $9.8 million in current joint interest billings receivables as of December 31, 2024 and 2023, respectively.

Inventories

Inventories consisted of $167.5 million and $143.0 million of materials and supplies and $3.4 million and $9.1 million of hydrocarbons as of December 31, 2024 and 2023, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value. We recorded write downs of $1.8 million, $7.4 million and $1.5 million during the years ended December 31, 2024, 2023 and 2022 for materials and supplies inventories as Other expenses, net in the consolidated statements of operations and other in the consolidated statements of cash flows.

Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.

Exploration and Development Costs

The Company follows the successful efforts method of accounting for its 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.

The Company evaluates unproved property periodically for impairment. The impairment assessment considers results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If it is determined that future appraisal drilling or development activities are unlikely to occur, the associated capitalized costs are recorded as exploration expense in the consolidated statement of operations.

Depletion, Depreciation and Amortization

Proved properties and support equipment and facilities are depleted using the unit‑of‑production method based on estimated proved oil and gas reserves. Capitalized exploratory drilling costs that result in a discovery of proved reserves and development costs are depleted using the unit‑of‑production method based on estimated proved developed oil and gas reserves for the related field.

Depreciation and amortization of other property is computed using the straight-line method over the assets’ estimated useful lives (not to exceed the lease term for leasehold improvements), ranging fromone toeight years.

Amortization of deferred financing costs is computed using the straight‑line method over the life of the related debt.

Capitalized Interest

Interest costs from external borrowings are capitalized on major projects with an expected construction period ofone year or longer. Capitalized interest is added to the cost of the underlying asset and is depleted on the unit‑of‑production method in the same manner as the underlying assets.

Asset Retirement Obligations

The Company accounts 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.

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.

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.

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.

Derivative Instruments and Hedging Activities

We utilize oil derivative contracts to mitigate our exposure to commodity price risk associated with our anticipated future oil production. These derivative contracts consist of collars, put options, call options and swaps. We also have used interest rate derivative contracts to mitigate our exposure to interest rate fluctuations related to our long‑term debt. Our derivative financial instruments are recorded on the balance sheet as either assets or liabilities and are measured at fair value. We do not apply hedge accounting to our derivative contracts. See Note 9—Derivative Financial Instruments.

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.

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, 2024 and 2023, we hadno 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 oil sales at the spot price on the date of sale. The derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month of or month after the sale.

Oil and gas revenue is composed of the following:

Equity‑based Compensation

For equity‑based compensation awards, compensation expense is recognized in the Company’s financial statements over the awards’ vesting periods based on their grant date fair value. The Company utilizes (i) the closing stock price on the date of grant to determine the fair value of service vesting restricted stock units and (ii) a Monte Carlo simulation to determine the fair value of restricted stock units with a combination of market and service vesting criteria. Forfeitures are recognized in the period in which they occur.

Income Taxes

The Company accounts for income taxes as required by ASC 740—Income Taxes. Under this method, deferred income taxes are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. 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.

We recognize tax benefits from uncertain tax positions only if it is more likely than not that the tax position will be sustained upon examination by the tax authorities, based on the technical merits of the position. Accordingly, we measure tax benefits from such positions based on the most likely outcome to be realized.

Foreign Currency Translation

The U.S. dollar is the functional currency for all of the Company’s material foreign operations. Foreign currency transaction gains and losses and adjustments resulting from translating monetary assets and liabilities denominated in foreign currencies are included in other expenses. Cash balances held in foreign currencies are not significant, and as such, the effect of exchange rate changes is not material to any reporting period.

Concentration of Credit Risk

Our revenue can be materially affected by current economic conditions and the price of oil and natural gas. However, based on the current demand for crude oil and natural gas and the fact that alternative purchasers are readily available, we believe that the loss of our marketing agents and/or any of the purchasers identified by our marketing agents would not have a long‑term material adverse effect on our financial position or results of international operations. The economic disruption resulting from Russia’s continued war in Ukraine, ongoing instability in the Middle East, a potential global recession, inflationary pressures and other varying macroeconomic conditions could materially impact the Company's business in future periods. Any potential disruption will depend on the duration and intensity of these events, which are highly uncertain and cannot be predicted at this time.

Recent Accounting Standards

Recently Adopted

In November 2023, the FASB issued “ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” The amendment requires disclosures of significant segment expenses that are regularly provided to the chief operating decision maker (“CODM”) and included within each reported measure of segment profit or loss, an amount and description of its composition for other segment items, and interim disclosures of a reportable segment’s profit of loss and assets. The amendments are effective for fiscal years beginning after December 15, 2023, and for interim periods within fiscal years beginning after December 15, 2024.

Not Yet Adopted

In December 2023, the FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures (Topic 740).” The amendments focus on income tax disclosures around effective tax rates and cash income taxes paid. The amendments in the ASU are effective for annual periods beginning after December 15, 2024. Early adoption is permitted, however, we do not plan to early adopt ASU 2023-09.

3. Acquisitions and Divestitures

2024 Transactions

In March 2024, Kosmos completed the acquisition of an additional 16.7% participating interest in the Tiberius area in Keathley Canyon Blocks 920 and 964 offshore Gulf of America. As a result of the transaction, Kosmos’ participating interest in Tiberius increased from 33.3% to 50.0%.

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

2023 Transactions

In February 2023, Kosmos entered into a petroleum contract covering Block EG-01 offshore Equatorial Guinea with the Republic of Equatorial Guinea. Kosmos holds a 24% non-operated participating interest in the block. Block EG-01 currently comprises approximately 59,400 acres (240 square kilometers), with a first exploration period ofthree years from the effective date (March 1, 2023).

In November 2023, BP decided not to participate in the future development and exploitation of the Yakaar and Teranga discoveries. In accordance with the provisions of the Contract for Exploration and Production Sharing of Hydrocarbons for the Cayar Offshore Profond Block (the “Contract”) and the related Joint Operating Agreement (the “JOA”), BP has waived its rights in respect of the Yakaar and Teranga discoveries. As provided in the JOA, Kosmos has assumed BP’s participating interest under the Contract and the JOA and has become operator of the Cayar Offshore Profond Block, with customary government approvals having been received effective January 18, 2024. The participating interests in the Cayar Offshore Profond Block are: Kosmos 90% and PETROSEN 10%, with PETROSEN having the right to increase its participating interest after issuance of an exploitation authorization to up to 35%.

2022 Transactions

In March 2022, Kosmos completed the acquisition of an additional 5.5% interest in Winterfell area in Green Canyon Blocks 943, 944, 987 and 988, offshore Gulf of America, and an additional 1.5% interest in Green Canyon blocks 899 and 900 for $9.6 million. Additionally, in September 2022, Kosmos completed the acquisition of an additional 3.2% interest in the Winterfell area in Green Canyon Blocks 943, 944, 987 and 988 and an additional 1.4% interest in Green Canyon Blocks 899 and 900 for $6.6 million. As a result of thetwo transactions, our participating interests in the Green Canyon Blocks 943, 944, 987 and 988 is now 25.0% and our participating interests in the Green Canyon Blocks 899 and 900 is 37.8%.

In May 2022, Kosmos and its joint venture partners agreed with the Ministry of Hydrocarbons and Mining Development of Equatorial Guinea to extend the Block G petroleum contract term harmonizing the expiration of the Ceiba Field and Okume Complex production licenses (from 2029 and 2034 respectively) to 2040.

In June 2022, Kosmos completed the acquisition of an additional 5.9% interest in the Kodiak oil field from Marubeni by exercising our preferential right to purchase for a total purchase price of approximately $29.0 million. The purchase price was based on an initial purchase price of $38.3 million reduced by certain purchase adjustments totaling approximately $9.3 million. The purchase price allocation was based on the estimated fair value of identifiable assets acquired and liabilities assumed primarily comprised of $27.1 million of oil and gas properties, net. As a result of the transaction, our working interest increased from 29.1% to 35.0%.

In June 2022, at the conclusion of the second exploration period, Block C12 offshore Mauritania was relinquished.

In October 2022, we entered into a farm-out agreement with Panoro Energy ASA (Panoro) to farm-out a 6.0% participating interest in Block S offshore Equatorial Guinea, which reduced our participating interest in Block S to 34.0%, in exchange for cash consideration totaling approximately $1.8 million. In March 2023, the transaction was approved by the Government of Equatorial Guinea and the farm-out agreement was closed.

In October 2021, Kosmos completed the acquisition of Anadarko WCTP Company (“Anadarko WCTP”), a subsidiary of Occidental Petroleum Corporation, which owns a participating interest in the WCTP Block and DT Block offshore Ghana, including an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN Fields. Following closing of the acquisition, Kosmos’ interest in the Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN Fields increased from 17.0% to 28.1%. Under the DT Block Joint Operating Agreement, certain joint venture partners have pre-emption rights in the Jubilee Unit Area and the TEN Fields. In November 2021, we received notice from Tullow Oil plc (“Tullow”) that they were exercising their pre-emption rights in relation to Kosmos’ acquisition of Anadarko WCTP. After execution of definitive transaction documentation and receipt of government approvals, Kosmos concluded the pre-emption transaction with Tullow in March 2022. Following the completion of the pre-emption process, Kosmos’ interest in the Jubilee Unit Area decreased from 42.1% to 38.6% and Kosmos’ interest in the TEN Fields decreased from 28.1% to 20.4%. Tullow paid Kosmos $118.2 million in cash consideration after post closing adjustments for the pre-emption. During the first quarter of 2022, our oil and gas properties, net balance was reduced by $175.5 million, which includes the cash proceeds and net liabilities transferred to the purchaser as a result of concluding the Tullow pre-emption transaction. The difference in the net book value of the proved property, net liabilities transferred and adjusted purchase price qualified for treatment as a recovery of cost and normal retirement under ASC 932, which resulted in no gain or loss being recognized.

4. Receivables

Receivables consisted of the following:

The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company for shared costs. Joint interest billings are classified as current and long-term receivables based on when collection is expected to occur.

Long-term receivables

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal obligating us to finance a portion of the respective national oil companies’ share of certain development costs incurred for the GTA Phase 1 project. The amount financed by Kosmos is to be repaid with interest through the national oil companies’ share of future revenues. As of December 31, 2024 and 2023, the principal balance due from the national oil companies was $280.1 million and $259.2 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. As of December 31, 2024 and 2023, accrued interest on the balance due from the national oil companies was $56.6 million and $37.3 million, respectively, which is classified as Long-term receivables in our consolidated balance sheets. Interest income on the long-term notes receivable was $19.3 million, $15.9 million and $10.1 million for the years ended December 31, 2024, 2023 and 2022, respectively.

In August 2021, BP, as the operator of the Greater Tortue project (“BP Operator”), with the consent of the Greater Tortue Unit participants and the respective States, agreed to sell the Greater Tortue FPSO to an affiliate of BP Operator (“BP Buyer”) once the construction has been completed by Technip Energies and the Greater Tortue FPSO has been commissioned (the “FPSO Handover”). As a result of the above transactions entered into by BP Operator, Kosmos recognized a Long-term receivable of $200.2 million from BP Operator for our share of the consideration paid from BP Buyer to and held by BP Operator as well as a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Greater Tortue FPSO.

As of December 31, 2022, this Long-term receivable was non-cash settled against obligations payable to BP Operator, which included $132.4 million and $67.8 million of non-cash capital expenditures during the fourth quarter of 2021 and the first quarter of 2022, respectively. Delivery of the Greater Tortue FPSO to BP Buyer and FPSO Handover occurred during the fourth quarter of 2024. The $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Greater Tortue FPSO was non-cash settled against FPSO asset costs in our consolidated balance sheet as of December 31, 2024, reducing both assets and liabilities. These non-cash impacts are excluded from the statement of cash flows.

5. Property and Equipment

Property and equipment is stated at cost and consisted of the following:

We recorded depletion expense of $419.3 million, $411.6 million and $471.4 million and depreciation expense of $3.7 million, $3.7 million and $3.6 million for the years ended December 31, 2024, 2023 and 2022, respectively. In connection with fair value assessments for oil and gas proved properties, we recorded asset impairments of 222.3 million and $450.0 million related to the TEN Fields in Ghana during the years ended December 31, 2023 and 2022, respectively in our consolidated statement of operations. No proved property impairments were recorded for the year ended December 31, 2024. During the year ended December 31, 2024 we wrote off $37.6 million of capitalized exploratory costs associated with the S-5 exploration well.

During the year ended December 31, 2024, additions to our proved properties primarily related to continued infill development drilling campaign in the Jubilee Field in Ghana, the Ceiba and Okume infill development drilling campaign in Equatorial Guinea, development costs associated with Phase 1 of the Greater Tortue Ahmeyim project in Mauritania and Senegal, the first phase of the Winterfell development project and the Odd Job Field subsea pump installation in the Gulf of America, offset by the non-cash settlement of the $200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue FPSO against FPSO asset costs.

During the year ended December 31, 2023, additions to our unproved properties primarily related to the Winterfell development project and the drilling of the Tiberius infrastructure-led exploration prospect. Additions to our proved properties for the year ended December 31, 2023 primarily related to continued infill development in the Jubilee Field in Ghana including the successful startup of the Jubilee Southeast project with the installation of a new subsea production manifold, the Odd Job Field subsea pump installation in the Gulf of America and continued progress on the development of the Greater Tortue Ahmeyim project in Mauritania/Senegal.

6. Suspended Well Costs

The Company capitalizes exploratory well costs as unproved properties within oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. Well costs are charged to exploration expense if the exploratory well is determined to be impaired.

The following table reflects the Company’s capitalized exploratory well costs on drilled wells as of and during the years ended December 31, 2024, 2023 and 2022.

(1)Activity for the year ended December 31, 2022 represents the reclassification of exploratory well costs associated with the Winterfell discovery in Green Canyon Block 944 in the Gulf of America.

(2)Activity for the year ended December 31, 2024 represents the impairment of exploratory well costs associated with the Asam discovery in Block S offshore Equatorial Guinea. Activity for the year ended December 31, 2022 represents the impairment of exploratory well costs associated with the BirAllah and Orca discoveries as a result of the expiration of the exploration period of Block C8 in June 2022.

The following table provides aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:

As of December 31, 2024, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal and the Tiberius discovery located in Keathley Canyon Block 964 in the Outer Wilcox play in the Gulf of America.

Yakaar and Teranga Discoveries — In May 2016, we drilled the Teranga-1 exploration well in the Cayar Offshore Profond Block offshore Senegal, which encountered hydrocarbon pay. In June 2017, we drilled the Yakaar-1 exploration well in the Cayar Offshore Profond Block offshore Senegal, which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted to the Government of Senegal. In September 2019, we drilled the Yakaar-2 appraisal well which encountered hydrocarbon pay. The Yakaar-2 well was drilled approximately nine kilometers from the Yakaar-1 exploration well. In March 2024, the current phase of the Cayar Block exploration license was extended an additionaltwo years to July 2026. The Yakaar and Teranga discoveries continue to be progressed as a joint development. During 2024, we continued progressing appraisal studies and maturing concept design. Following additional evaluation, a final investment decision for the development of the project is expected to be made.

Tiberius Discovery — In July 2023, we spud the Tiberius infrastructure-led exploration prospect located in Block 964 of Keathley Canyon in the Gulf of America, which encountered hydrocarbon pay. Initial fluid and core analysis supports the production potential of the well, which characteristics analogous with similar nearby discoveries in the Wilcox trend. In March 2024, we completed the acquisition of an additional 16.7% participating interest in the Keathley Canyon Blocks 920 and 964, offshore Gulf of America. As a result of the transaction, Kosmos’ participating interest in the Tiberius discovery area increased from 33.3% to 50.0%. The Tiberius project is being analyzed as a phased development with discussions currently ongoing with our partner to finalize the development plan. Following additional evaluation, a final investment decision for the development of the project is expected to be made.

7. Leases

We have commitments under operating leases primarily related to office leases. Our leases have initial lease terms ranging fromone year toten years. Certain lease agreements contain provisions for future rent increases.

The components of lease cost for the years ended December 31, 2024, 2023 and 2022 is as follows:

(1)Includes $10.7 million, $16.0 million and $12.4 million during the years ended December 31, 2024, 2023 and 2022, respectively, of costs associated with short-term drilling contracts.

Other information related to operating leases at December 31, 2024 and 2023, is as follows:

The table below presents supplemental cash flow information related to leases during the years ended December 31, 2024, 2023 and 2022:

(1)Represents costs associated with short-term drilling contracts.

Future minimum rental commitments under our leases at December 31, 2024, are as follows:

(1)Does not include purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments, in our petroleum contracts.

8. Debt

(1)Includes $30.4 million and $20.8 million of unamortized deferred financing costs related to the Facility, $14.1 million and $13.3 million of unamortized deferred financing costs and discounts related to the Senior Notes, and $$11.1 million andnil of unamortized deferred financing costs related to the 3.125% Convertible Senior Notes as of December 31, 2024 and December 31, 2023, respectively.

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 April 2024, in conjunction with the Spring borrowing base redetermination, the Company executed an amendment and restatement of the Facility. The amendment and restatement included the following material changes: an increase in the Facility size and borrowing base capacity to $1.35 billion (from $1.25 billion), an increase in the interest margin by 0.25% or 0.50%, depending on the length of time that has passed from the date the Facility was entered into, and an extension in the tenor by approximately three years (final maturity date now occurs December 31, 2029). The amended Facility size and borrowing base capacity of approximately $1.35 billion was capped by total commitments of approximately $1.21 billion as of June 30, 2024. As part of the amendment and restatement, the Company recognized a loss on debt modifications and extinguishments of approximately $22.0 million during the second quarter of 2024. In September 2024, we addedtwo new lenders to the Facility syndicate, increasing total commitments by approximately $145.0 million to the full Facility size and borrowing base capacity of $1.35 billion. In October 2024, during the Fall 2024 borrowing base redetermination, the Company’s lending syndicate approved a borrowing base of $1.35 billion. As of December 31, 2024, borrowings under the Facility totaled $900.0 million and the undrawn availability under the Facility was $450 million.

When our net leverage ratio exceeds 2.50 x, 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 nextsix-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 net leverage ratio was 2.54 x, partially due to pre-production operating costs associated with the GTA Phase 1 project. Our next financial covenant assessment date is March 31, 2025, after which date we could be required to restrict approximately $66.0 million in cash as required under the terms of the Facility unless otherwise waived by the lenders. As of December 31, 2023 our net leverage ratio was below 2.50 x.

Interest on the Facility is the aggregate of the applicable margin (4.00% to 5.50%, depending on the length of time that has passed from the date the Facility was entered into), plus the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published. Interest is payable on the last day of each interest period (and, if the interest period is longer thansix months, on the dates falling atsix-month intervals after the first day of the interest period). We pay commitment fees on the undrawn and unavailable portion of the total commitments, if any. Commitment fees are equal to 30% per annum of the then-applicable respective margin when a commitment is available for utilization and, equal to 20% per annum of the then-applicable respective margin when a commitment is not available for utilization. We recognize interest expense in accordance with ASC 835—Interest, which requires interest expense to be recognized using the effective interest method. We determined the effective interest rate based on the estimated level of borrowings under the Facility.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expiresone 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, 2024, we hadno 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 below contained in the Facility as of September 30, 2024 (the most recent assessment date), which requires the maintenance of:

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

•the loan life cover ratio (as defined in the glossary), not less than 1.10 x through September 30, 2027 and 1.30 x after September 30, 2027; and

•the interest cover ratio (as defined in the glossary), not less than 2.25 x; and

•the debt cover ratio (as defined in the glossary), not more than 3.50 x.

The Facility contains customary cross default provisions.

Corporate Revolver

On March 31, 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement with a total size of $250 million and a maturity date of December 31, 2024. In April 2024, in connection with the amendment and restatement of the Facility, we amended the Corporate Revolver reducing the borrowing capacity from $250.0 million to $165.0 million. In October 2024, pursuant to a voluntary cancellation notice sent by the Company, the Corporate Revolver was terminated.

7.125% Senior Notes due 2026

In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of approximately $640.0 million after deducting commissions and other expenses. We used the net proceeds to redeem all of the previously issued 7.875% Senior Secured Notes due 2021, repay a portion of the outstanding indebtedness under the Corporate Revolver and pay fees and expenses related to the redemption, repayment and the issuance of the 7.125% Senior Notes.

The 7.125% Senior Notes mature on April 4, 2026. We will pay interest in arrears on the 7.125% Senior Notes each April 4 and October 4, commencing on October 4, 2019. The 7.125% 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 all borrowings under the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and 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 7.125% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of $400.0 million of the 7.125% Senior Notes pursuant to the Company’s cash tender offers for portions of the 7.125% Senior Notes, the 7.750% Senior Notes, and the 7.500% Senior Notes announced on September 9, 2024 (the “Tender Offers”). The 7.125% Senior Notes contain customary cross default provisions.

On or after April 4, 2022, the Company may redeem all or a part of the 7.125% Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:

We may also redeem the 7.125% Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the 7.125% Senior Notes at a price equal to the principal amount of the 7.125% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the 7.125% Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

Upon the occurrence of a change of control triggering event as defined under the 7.125% Senior Notes indenture, the Company will be required to make an offer to repurchase the 7.125% Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

If we sell assets, under certain circumstances outlined in the 7.125% Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the 7.125% Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the 7.125% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

The 7.125% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company’s subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the 7.125% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. The 7.125% Senior Notes contain customary cross default provisions.

7.750% Senior Notes due 2027

In October 2021, the Company issued $400.0 million of 7.750% Senior Notes and received net proceeds of approximately $395.0 million after deducting fees. We used the net proceeds, together with cash on hand, to refinance the $400.0 million Bridge Notes (which were issued during the fourth quarter of 2021 in connection with the completion of the acquisition of Anadarko WCTP) and to pay expenses related to the issuance of the 7.750% Senior Notes.

The 7.750% Senior Notes mature on May 1, 2027. Interest is payable in arrears each May 1 and November 1, commencing on May 1, 2022. The 7.750% 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 all borrowings under the 7.125% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and 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 7.750% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of

$50.0 million of the 7.750% Senior Notes pursuant to the Tender Offers. The 7.750% Senior Notes contain customary cross default provisions.

On or after November 1, 2023, the Company may redeem all or a part of the 7.750% Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:

We may also redeem the 7.750% Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the 7.750% Senior Notes at a price equal to the principal amount of the 7.750% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the 7.750% Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

Upon the occurrence of a change of control triggering event as defined under the 7.750% Senior Notes indenture, the Company will be required to make an offer to repurchase the 7.750% Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

If we sell assets, under certain circumstances outlined in the 7.750% Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the 7.750% Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the 7.750% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

The 7.750% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the 7.750% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. The 7.750% Senior Notes contain customary cross default provisions.

7.500% Senior Notes due 2028

In March 2021, the Company issued $450.0 million of 7.500% Senior Notes and received net proceeds of approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general corporate purposes.

The 7.500% Senior Notes mature on March 1, 2028. Interest is payable in arrears each March 1 and September 1, commencing on September 1, 2021. The 7.500% 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 all borrowings under the 7.125% Senior Notes, the 7.750% Senior Notes, the 8.750% Senior Notes and 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 7.500% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125% Senior Notes, the 7.750% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes. On September 24, 2024, the Company completed the repurchase of an aggregate principal amount of approximately $49.7 million of the 7.500% Senior Notes pursuant to the Tender Offers. The 7.500% Senior Notes contain customary cross default provisions.

On or after March 1, 2024, the Company may redeem all or a part of the 7.500% Senior Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest:

We may also redeem the 7.500% Senior Notes in whole, but not in part, at any time if changes in tax laws impose certain withholding taxes on amounts payable on the 7.500% Senior Notes at a price equal to the principal amount of the 7.500% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the 7.500% Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

Upon the occurrence of a change of control triggering event as defined under the 7.500% Senior Notes indenture, the Company will be required to make an offer to repurchase the 7.500% Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

If we sell assets, under certain circumstances outlined in the 7.500% Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the 7.500% Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the 7.500% Senior Notes, plus accrued and unpaid interest to, but excluding, the repurchase date.

The 7.500% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company’s subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the 7.500% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. The 7.500% Senior Notes contain customary cross default provisions.

8.750% Senior Notes due 2031

In September 2024, the Company issued $500.0 million of 8.750% Senior Notes and received net proceeds of approximately $494.9 million after deducting fees. We used the net proceeds, together with cash on hand, to fund the Tender Offers and pay expenses related to the issuance of the 8.750% Senior Notes.

The 8.750% Senior Notes mature on October 1, 2031. Interest is payable in arrears each April 1 and October 1, commencing on April 1, 2025. The 8.750% 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 all borrowings under the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and 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 8.750% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company’s Gulf of America assets and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and that guarantee the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 3.125% Convertible Senior Notes. The 8.750% Senior Notes contain customary cross default provisions.

At any time prior to October 1, 2027, and subject to certain conditions, the Company may, on one or more occasions, redeem up to 40% of the original principal amount of the 8.750% Senior Notes with an amount not to exceed the net cash proceeds of certain equity offerings at a redemption price of 108.750% of the outstanding principal amount of the 8.750% Senior Notes, together with accrued and unpaid interest and premium, if any, to, but excluding, the date of redemption. Additionally, at any time prior to October 1, 2027, the Company may, on any one or more occasions, redeem all or part of the 8.750% Senior Notes at a redemption price equal to 100%, plus any accrued and unpaid interest, and plus a “make-whole” premium. On and after October 1, 2027, the Company may redeem all or part of the 8.750% Senior Notes at the following redemption prices (expressed as a percentage of principal amount), plus accrued and unpaid interest, if any, on the notes redeemed during the twelve-month period indicated beginning on October 1 of the years indicated below:

We may also redeem the 8.750% Senior Notes in whole, but not in part, at any time if changes in tax law impose certain withholding taxes on amounts payable of the 8.750% Senior Notes at a price equal to the principal amount of the 8.750% Senior Notes plus accrued interest and additional amounts, if any, as may be necessary so that the net amount received by each holder after any withholding or deduction on payments of the 8.750% Senior Notes will not be less than the amount such holder would have received if such taxes had not been withheld or deducted.

Upon the occurrence of a change of control triggering event as defined under the 8.750% Senior Notes indenture, the Company will be required to make an offer to repurchase the 8.750% Senior Notes at a repurchase price equal to 101% of the principal amount, plus accrued and unpaid interest to, but excluding, the date of repurchase.

If we sell assets, under certain circumstances outlined in the 8.750% Senior Notes indenture, we will be required to use the net proceeds to make an offer to purchase the 8.750% Senior Notes at an offer price in cash in an amount equal to 100% of the principal amount of the 8.750% Senior Notes, plus accrued an unpaid interest to, but excluding, the repurchase date.

The 8.750% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company’s subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. Certain of these covenants will be terminated if the 8.750% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing.

3.125% Convertible Senior Notes due 2030

In March 2024, the Company issued $400.0 million of 3.125% Convertible Senior Notes (the “3.125% Convertible Senior Notes”) and received net proceeds of $390.4 million after deducting fees.

The 3.125% Convertible Senior Notes mature on March 15, 2030, unless earlier converted, redeemed or repurchased. 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 all borrowings under the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 8.750% 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 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 8.750% Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries. The 3.125% Convertible Senior Notes are guaranteed on a subordinated, unsecured basis by certain or existing subsidiaries that borrow under or guarantee the Facility and guarantee on a subordinated basis the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes and the 8.750% Senior Notes, and, in certain circumstances, certain of our other existing or future subsidiaries.

Holders of the 3.125% Convertible Senior Notes may convert all or any portion of their 3.125% Convertible Senior Notes at their option at any time prior to the close of business on the business day immediately preceding December 15, 2029 only under the following circumstances:

•during any calendar quarter commencing after the calendar quarter ending on June 30, 2024 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during a period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater that or equal to 130% of the conversion price on each applicable trading day;

•during thefive business day period after anyfive consecutive trading day period (the “measurement period”) in which the trading price per $1,000 principal amount of 3.125% Convertible Senior Notes for each trading day of the measurement period was less that 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day;

•if we call any or all of the 3.125% Convertible Senior Notes for redemption, the 3.125% Convertible Senior Notes called (or deemed called) for redemption may be converted at any time prior to the close of business on the second scheduled trading day immediately preceding the redemption date; or

•upon the occurrence of certain specified corporate events.

On or after December 15, 2029 until the close of business on the second scheduled trading day immediately preceding the maturity date, holders may convert at any time all or a portion of their 3.125% Convertible Senior Notes at the option of the holder.

The conversion rate for the 3.125% Convertible Senior Notes is initially 142.4501 share of common stock per $1,000 principal amount of 3.125% Convertible Senior Notes (which is equivalent to an initial conversion price of approximately $7.02 per share of our common stock), subject to adjustments.

Upon conversion, we will pay cash up to the aggregate principal amount of the 3.125% Convertible Senior Notes to be converted and pay or deliver, as the case may be, cash, shares of our common stock or a combination of cash and shares of our common stock, at our election in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the 3.125% Convertible Senior Notes being converted. The amount of cash and shares of our common stock, if any, due upon conversion will be based on a daily conversion value calculated on a proportionate basis for each trading day in a 40 consecutive trading day observation period.

In addition, following certain corporate events that occur prior to the maturity date or if we deliver a notice of redemption, we will, in certain circumstances, increase the conversion date for a holder who elects to convert its 3.125% Convertible Senior Notes in connection with such a corporate event or to convert its 3.125% Convertible Senior Notes called (or deemed called) for redemption in connection with such notice of redemption, as the cause may be.

Other than in connection with certain tax law changes, we may not redeem the notes prior to March 22, 2027. We may redeem for cash all or any portion of the 3.125% Convertible Senior Notes, at our option, on or after March 22, 2027 and prior to the 41 st scheduled trading day immediately preceding the maturity date, if the last reported sale price of our common stock has been at least 130% of the conversion price then in effect for at least 20 trading days (whether or not consecutive), including the trading day immediately preceding the date on which the Company provides notice of redemption, during an 30 day consecutive trading day period ending on, and including, the trading day immediately preceding the date on which we provide the related notice of redemption, at a redemption price equal to 100% of the principal amount of the 3.125% Convertible Senior Notes to be redeemed, plus accrued and unpaid interest to, but excluding, the redemption date. We are not required to redeem or retire the 3.125% Convertible Senior Notes periodically. We may not elect to redeem less than all of the outstanding 3.125% Convertible Senior Notes unless at least $75.0 million aggregate principal amount of 3.125% Convertible Senior Notes are outstanding and not subject to redemption as of the time we send the related redemption notice. The 3.125% Convertible Senior Notes indenture contains customary terms and covenants.

The Company recorded the 3.125% Convertible Senior Notes, including the debt itself and all embedded derivatives, at cost less debt issuance costs of $9.6 million and has presented the 3.125% Convertible Senior Notes as a single financial instrument in Long-term debt, net in our consolidated balance sheet. No portion of the embedded derivative required bifurcation from the host debt contract. As of December 31, 2024, the effective annual interest rate on the 3.125% Convertible Senior Notes is approximately 3.70%, including amortization of debt issuance costs.

Capped Call Transactions

In connection with the issuance of the 3.125% Convertible Senior Notes, the Company used $49.8 million of the net proceeds from the issuance of the 3.125% Convertible Senior Notes to enter into 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.

The Capped Call Transactions have an initial cap price of $10.80 per share, which represents a premium of 100% over the last reported sale price of our common stock on March 5, 2024, and is subject to certain adjustments under the terms of the Capped Call Transactions. The Capped Call Transactions cover, initially, the number of shares of our common stock underlying the 3.125% Convertible Senior Notes, subject to anti-dilution adjustments substantially similar to those applicable to the conversion rate of the 3.125% Convertible Senior Notes.

The Capped Call Transactions qualify for a derivative scope exception as they are indexed to our common stock and are not required to be accounted for as a separate derivative. Consequently, the Capped Call Transactions have been included as a net reduction to additional-paid-in-capital within stockholders’ equity in our consolidated balance sheet and do not require subsequent remeasurement.

Principal Debt Repayments

At December 31, 2024, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:

(1)Includes the scheduled maturities for outstanding principal debt balances. The scheduled maturities of debt related to the Facility as of December 31, 2024 are based on our level of borrowings and our estimated future available borrowing base commitment levels in future periods. 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.

Interest and other financing costs, net

Interest and other financing costs, net incurred during the period comprised of the following:

Cash payments for interest totaled $194.8 million, $213.4 million and $170.1 million for the years ended December 31, 2024, 2023 and 2022. Capitalized interest for the years ended December 31, 2024, 2023 and 2022 was $168.7 million, $138.7 million and $84.3 million, respectively, primarily relates to spend on the Greater Tortue Ahmeyim Phase 1 project. After first gas production on the Greater Tortue Ahmeyim Phase 1 project, which was achieved on December 31, 2024, we will no longer capitalize interest on the project.

9. Derivative Financial Instruments

We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.

We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820—Fair Value Measurements and Disclosures.

Oil Derivative Contracts

The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average prices per Bbl for those contracts as of December 31, 2024. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.

In January 2025, we entered into Dated Brent three-way collar contracts for 2.0 MMBbl from January 2025 through December 2025 with a sold put price of $55.00 per barrel, a floor price of $70.00 per barrel and a ceiling price of $85.00 per barrel.

Interest Rate Derivative Contracts

The following table summarized our open interest rate swaps whereby we pay a fixed rate of interest and the counterparty pays a variable SOFR-based rate as of December 31, 2024:

See Note 10—Fair Value Measurements for additional information regarding the Company’s derivative instruments.

The following tables disclose the Company’s derivative instruments as of December 31, 2024 and 2023 and gain/(loss) from derivatives during the years ended December 31, 2024, 2023 and 2022.

Offsetting of Derivative Assets and Derivative Liabilities

Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of December 31, 2024 and 2023, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.

10. Fair Value Measurements

In accordance with ASC 820—Fair Value Measurements, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:

•Level 1 — quoted prices for identical assets or liabilities in active markets.

•Level 2 — quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.

•Level 3 — unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2024 and 2023, for each fair value hierarchy level:

The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short‑term nature of these instruments. Our long‑term receivables, after any allowances for credit losses, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.

Commodity Derivatives

Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for the respective index, (iii) a credit‑adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for the respective index. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market‑quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9—Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.

Provisional Oil Sales

The value attributable to provisional oil sales derivative is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for the respective index over the term of the pricing period designated in the sales contract and the spot price on the lifting date.

Interest Rate Derivatives

Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable SOFR-based rate. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) SOFR yield curves provided by independent third parties and corroborated with forward active market-quoted SOFR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.

Decommissioning Trust Fund

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. Each partner will contribute annually to the trust in proportion to its respective paying interest of the estimated future dismantlement, abandonment and restoration costs associated with the decommissioning of the Jubilee Field. Contributions to the trust are used by the trustee of the fund, the Bank of Ghana, to purchase and sell authorized securities at the direction of the Jubilee unit partners.

As of December 31, 2024, the investments held in the decommissioning trust fund are US Treasury debt securities. We have classified the investments as trading securities and recorded such investments at their fair market value as a long-term investment in our consolidated balance sheet using observable inputs including Kosmos’ share of the fund and broker/dealer bid/ask prices of the investments held by the fund at December 31, 2024. Contributions made to the decommissioning trust are reported as investing activities in our consolidated statement of cash flows. All realized and unrealized gains and losses resulting from the sales and maturities or changes in fair value of the securities are recognized in Other income, net. For the year ended December 31, 2024, we contributed $11.5 million to the decommissioning trust fund.

The following table summarizes the cost and fair value, purchases, proceeds from the sales and maturities, and the unrealized gains (losses) for Kosmos’ portion of the investments in debt securities held by the decommissioning trust at December 31, 2024 and 2023:

(1)Net proceeds includes realized gains or losses, interest income, and fees.

The following table presents the costs and fair values of investments in debt securities held in the decommissioning trust fund according to the contractual maturities at December 31, 2024 and 2023:

Debt

The following table presents the carrying values and fair values at December 31, 2024 and 2023:

The carrying values of our 7.125% Senior Notes,7.750% Senior Notes,7.500% Senior Notes,8.750% Senior Notes and 3.125% Convertible Senior Notes represent the principal amounts outstanding less unamortized discounts. The fair values of our 7.125% Senior Notes,7.750% Senior Notes,7.500% Senior Notes,8.750% Senior Notes and 3.125% Convertible Senior Notes are based on quoted market prices, which results in a Level 1 fair value measurement. The carrying values of the Facility approximate fair value since they are subject to short-term floating interest rates that approximate the rates available to us for those periods.

Nonrecurring Fair Value Measurements - Long-lived assets

Certain long-lived assets are reported at fair value on a non-recurring basis on the Company's consolidated balance sheet. These long-lived assets are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Our long-lived assets are reviewed for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

The Company calculates the estimated fair values of its long-lived assets using the income approach described in the ASC 820 — Fair Value Measurements. Significant inputs associated with the calculation of estimated discounted future net cash flows include anticipated future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These are classified as Level 3 fair value assumptions. The Company utilizes an average of third-party industry forecasts of Dated Brent, adjusted for location and quality differentials, to determine our pricing assumptions. In order to evaluate the sensitivity of the assumptions, we analyze sensitivities to prices, production, and risk adjustment factors.

No impairment of proved oil and gas properties was recognized for the year December 31, 2024.

As a result of negative proved oil and gas reserve revisions at TEN, primarily driven by a change in the partnership’s development work scope for the TEN Fields and well performance, we reviewed our TEN long-lived assets for impairment at December 31, 2023, which resulted impairment charges of $222.3 million for the year ended December 31, 2023. The impairment charges resulted in a full impairment of the remaining book value of TEN reducing the carrying value of the TEN Fields tozero. As part of our impairment analysis, the average per barrel Dated Brent price of third-party industry forecasts used for purposes of determining discounted future cash flows was in the low-$80s adjusted for inflation. The expected future cash flows were discounted using a rate of approximately 10 percent which the Company believes is a market-based weighted average cost of capital for industry peers determined appropriate at the time of the valuation.

As a result of a negative proved oil and gas reserve revision at TEN, primarily driven by well performance, we reviewed our TEN long-lived assets for impairment at December 31, 2022, which resulted in impairment charges of $450.0 million for the year ended December 31, 2022, reducing the carrying value of the TEN Fields to the estimated fair value of $235.7 million as of December 31, 2022. As part of our impairment analysis, the average per barrel Dated Brent price of third-party industry forecasts used for purposes of determining discounted future cash flows was in the low-$80s adjusted for inflation. We also took account of the delayed future investment in the field. The expected future cash flows were discounted using a rate of approximately 10 percent which the Company believes is a market-based weighted average cost of capital for industry peers determined appropriate at the time of the valuation.

These impairment charges are included in Impairments of long-lived assets on the consolidated statement of operations. If we experience material declines in oil pricing expectations, increases in our estimated future expenditures or a decrease in our estimated production profile, our long-lived assets could be at risk of additional impairment.

11. Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations:

The asset retirement obligations reflect the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our oil and gas properties. The Company utilizes current cost experience to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and gas property balance. The liabilities incurred during 2024 are related to the infill drilling programs in the Jubilee Field in Ghana and the Ceiba and Okume Complex in Equatorial Guinea, the Winterfell development in the Gulf of America and the Greater Tortue Ahmeyim Phase 1 development project in Mauritania and Senegal. The revisions in estimated retirement obligations during 2024 and 2023 are related to changes in the estimated timing, scopes of work and costs.

12. Equity‑based Compensation

Restricted Stock Awards and Restricted Stock Units

Our Long-Term Incentive Plan (“LTIP”) provides for the granting of incentive awards in the form of stock options, stock appreciation rights, restricted stock awards, restricted stock units, among other award types. In June 2023, the Company’s stockholders approved the Amended and Restated Kosmos Energy Ltd. LTIP, which authorized an additional 17.0 million shares of common stock available for issuance under the LTIP. The LTIP as amended provides for the issuance of 78.5 million shares pursuant to awards under the LTIP. As of December 31, 2024, the Company had approximately 10.4 million shares that remain available for issuance under the LTIP.

The Company granted restricted stock units with service vesting criteria and with a combination of market and service vesting criteria under the LTIP. Substantially, all of these awards vest over athree year period. Upon vesting, restricted stock units become issued and outstanding stock.

The following table reflects the outstanding restricted stock units as of December 31, 2024:

(1)The restricted stock units with a combination of market and service vesting criteria may vest between 0% and 200% of the originally granted units depending upon market performance conditions. Awards vesting over or under target shares of 100% results in additional shares granted or forfeited, respectively, in the period the market vesting criteria is determined.

As of December 31, 2024, total equity‑based compensation to be recognized on unvested restricted stock units is $27.6 million over a weighted average period of 1.7 years.

For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to 200% of the awards granted. The grant date fair value ranged from $1.06 to $13.06 per award. The Monte Carlo simulation model utilizes multiple input variables that determined the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from 50.0% to 105.0%. The risk‑free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant ranged from 0.2% to 4.1%. The expected quarterly dividends ranged from $0.00 to $0.05 commensurate with our current dividend experience.

In January 2025, we granted 2.4 million service vesting restricted stock units and 3.0 million market and service vesting restricted stock units to our employees under our long-term incentive plan. We expect to recognize approximately $23.8 million of non-cash compensation expense related to these grants over the next three years.

We record equity-based compensation expense in General and administrative expenses in our consolidated statement of operations equal to the grant date fair value of share‑based payments over the vesting periods of the LTIP awards. The following table summarizes certain information related to our share-based payments:

13. Income Taxes

We provide for income taxes based on the laws and rates in effect in the countries in which our operations are conducted. The relationship between our pre‑tax income or loss from continuing operations and our income tax expense or benefit varies from period to period as a result of various factors which include changes in total pre‑tax income or loss, the jurisdictions in which our income (loss) is earned and the tax laws in those jurisdictions.

During the year ended December 31, 2024, our net deferred tax liability decreased by approximately $52.1 million primarily as a result of a tax rate change in Equatorial Guinea (discussed below) and the timing reversal of temporary differences. During the year ended December 31, 2023, our net deferred tax liability decreased by approximately $107.6 million primarily as a result of a $222.3 million impairment related to the TEN Field, which resulted in a reduction in our deferred tax liability of $77.8 million, with the remaining $29.8 million decrease in our deferred tax liability primarily related to the timing of the reversal of temporary differences. During the year ended December 31, 2022, our net deferred tax liability decreased by approximately $242.7 million, primarily as a result of a $450.0 million impairment related to the TEN Field, which resulted in a reduction in our deferred tax liability of approximately $157.6 million, and a $44.6 million of the decrease related to closing the Tullow pre-emption transaction in March 2022 (See Note 3 - Acquisitions and Divestitures), and the remaining $40.5 million decrease in our deferred tax liability primarily related to the timing of the reversal of temporary differences.

Income (loss) before income taxes is composed of the following:

The components of the provision for income taxes attributable to our income (loss) before income taxes consist of the following:

Our reconciliation of income tax expense (benefit) computed by applying our statutory rate and the reported effective tax rate on income or (loss) from continuing operations is as follows:

(1)The effective tax rate during the years ended December 31, 2024, 2023 and 2022, were impacted by (gains) and losses of $155.3 million, $(4.0) million and $21.0 million, respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits or where there are valuation allowances offsetting the corresponding deferred tax assets.

The effective tax rate for the United States is approximately (1%), (2%) and 10% for the years ended December 31, 2024, 2023 and 2022, respectively. The effective tax rate in the United States is impacted by the effect of non-deductible expenditures and equity-based compensation tax shortfalls and tax windfalls equal to the difference between the income tax benefit recognized for financial statement reporting purposes compared to the income tax benefit realized for tax return purposes. For the years ended December 31, 2024, 2023 and 2022, our effective tax rate in the United States is impacted by changes in valuation allowances on a portion of our deferred tax assets totaling $33.1 million, $12.1 million and $(12.3) million, respectively.

The effective tax rate for Ghana is approximately 35%,36% and 35% for the years ended December 31, 2024, 2023 and 2022, respectively. The effective tax rate in Ghana is impacted by non-deductible expenditures.

The effective tax rate for our producing entity in Equatorial Guinea is approximately (68)%,35% and 36% for the years ended December 31, 2024, 2023 and 2022, respectively, and is impacted by non-deductible expenditures. Equatorial Guinea changed the statutory rate from 35% to 25%, with an effective date of January 1, 2025. We remeasured the net deferred tax liability during the fourth quarter of 2024 which impacted the effective tax rate for the year.

Our operations in other foreign jurisdictions have a 0% effective tax rate because they reside in countries with minimal activity, a 0% statutory rate, or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.

Deferred tax assets and liabilities, which are computed on the estimated income tax effect of temporary differences between financial and tax bases in assets and liabilities, are determined using the tax rates expected to be in effect when taxes are actually paid or recovered. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows:

The Company has foreign net operating loss carryforwards of $128.6 million. Of these losses, we expect $70.7 million to expire in 2029 and, $58.0 million will not expire. Additionally, the Company has $461.6 million of United States net operating loss that will not expire. All of these losses currently have offsetting valuation allowances.

The Company is open to tax examinations in the United States for federal income tax return years 2021 through 2023, in Ghana for income tax return years 2020 through 2023, in Equatorial Guinea for income tax return years 2019 through 2023, in the United Kingdom for income tax years 2021 through 2023, in Senegal for income tax years 2020 through 2023, and in Mauritania from 2021 through 2023.

As of December 31, 2024, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.

14. Net Income (Loss) Per Share

In the calculation of basic net income per share, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income, if any. We calculate basic net income per share under the two‑class method. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if all outstanding awards under our LTIP were converted into shares of common stock or resulted in the issuance of shares of common stock that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations securities would not be dilutive to net loss per share and conversion into shares of common stock is assumed not to occur.

Basic net income (loss) per share is computed as (i) net income (loss), (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. The Company’s diluted net income (loss) per share is computed as (i) basic net income (loss), (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding.

(1)Our restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per share calculation.

(2)For the years ended December 31, 2024, 2023 and 2022, we excluded 3.3 million,0.0 million and 0.1 million outstanding restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive.

15. Commitments and Contingencies

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 none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.

As of December 31, 2024, we have a commitment to drillone development well in Equatorial Guinea.

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal, which obligate us separately to finance the respective national oil companies’ share of certain GTA Phase 1 development and production costs. Kosmos’ total share for thetwo agreements combined is currently estimated at approximately $370.0 million, of which $280.1 million has been incurred through December 31, 2024, excluding accrued interest.

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 $137.5 million as of December 31, 2024, net to Kosmos, which will be funded annually by Kosmos over an estimated 12 year period.

Performance Obligations

As of December 31, 2024 and 2023, the Company had performance bonds and supplemental bonds totaling $169.4 million and $194.1 million, respectively, related to bonding requirements stipulated by the BOEM and other third parties for anticipated plugging and abandonment costs of certain wells and the removal of certain facilities in our Gulf of America fields.

16. Additional Financial Information

Accrued Liabilities

Accrued liabilities consisted of the following:

Other Expenses, net

Other expenses, net incurred during the period is comprised of the following:

17. Business Segment Information

Kosmos is engaged in a single line of business, which is the exploration, development and production of oil and gas. At December 31, 2024, the Company had operations infour geographic reporting segments: Ghana, Equatorial Guinea, Mauritania/Senegal and the Gulf of America. The Company’s Chief Operating Decision Maker (“CODM”) is the Chief Executive Officer, who makes decisions about allocating resources and assessing performance for the entire company. To assess performance of the reporting segments, the CODM regularly reviews oil and gas revenues, oil and gas production costs, exploration expenses and capital expenditures by reporting segment in deciding how to allocate resources and in assessing performance. Capital expenditures, as defined by the Company, may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with our consolidated financial statements and notes thereto. Financial information for each reporting segment is presented below:

(2)Includes activity related to the interest pre-empted by Tullow prior to the March 17, 2022 closing date of the Tullow pre-emption transaction. Additionally, cash consideration of $118.2 million is included as a reduction in Consolidated capital expenditures for the year ended December 31, 2022.

(3)Includes activity related to our acquisition of an additional interest in the Kodiak oil field commencing June 9, 2022, the acquisition date. Additionally, cash consideration paid of $29.0 million is included in the Consolidated capital expenditures for the year ended December 31, 2022.

(1)Unsuccessful well costs are included in oil and gas assets when incurred.