Kosmos Energy Ltd. (KOS)

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

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

Overview

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

Recent Developments

Corporate

In March 2024, the Company issued $400.0 million of 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. The conversion rate for the 3.125% Convertible Senior Notes is initially 142.4501 shares of our 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.

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 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.

In April 2024, in conjunction with the Spring borrowing base redetermination, the Company executed an amendment and restatement of the Facility. As amended and restated, the Facility size and borrowing base capacity is approximately $1.35 billion (increased from $1.25 billion) and was capped by total commitments of approximately $1.21 billion as of June 30, 2024. In September 2024, we added two new lenders to the Facility syndicate, increasing current total commitments by approximately $145.0 million to the full Facility size and borrowing base capacity of $1.35 billion.

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 complete the repurchase of an aggregate principal amount of $400.0 million of the 7.125% Senior Notes, $50.0 million of the 7.750% Senior Notes, and approximately $49.7 million of the 7.500% Senior Notes and to pay expenses related to the issuance of the 8.750% Senior Notes.

In October 2024, pursuant to a voluntary cancellation notice sent by the Company, the Corporate Revolver was terminated.

Ghana

During the year ended December 31, 2024, Ghana production averaged approximately 120,900 Boepd gross (41,300 Boepd net).

The phased development of the Jubilee Field continued during 2024 bringing three production wells and two water injection wells online during the first half of 2024. We completed the three year infill drilling campaign in Ghana during the second quarter of 2024. The partnership is now conducting a new 4D seismic survey which started in early 2025. In December 2024, the partnership entered into a drilling rig contract for the next development drilling campaign in the Jubilee Field, which is expected to commence in the second quarter of 2025. The campaign is planned to include the drilling and completion of two in-fill wells in the Jubilee Field in 2025, both expected to be online in the third quarter of 2025. The rig will then undergo scheduled maintenance before returning for a planned four-well drilling campaign on Jubilee in 2026.

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During 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana. This interim gas sales agreement has been extended to November 2025 at a price of approximately $3.00 per MMBtu.

Gulf of America

During the year ended December 31, 2024, Gulf of America production averaged approximately 15,300 Boepd (net) (~83% oil).

In July 2024, we announced start-up of oil production at the Winterfell development in the Green Canyon area of the Gulf of America (25% working interest). The Winterfell project is a phased development with the initial two production wells of the first phase brought online in the third quarter of 2024. The third development well was drilled in the second quarter of 2024 and brought online in October 2024. Shortly after startup of the third well, production at the field was curtailed due to sand production from the third well seen at the production facility. In December 2024, production from Winterfell-1 and Winterfell-2 was restored and remediation work on Winterfell-3 is currently underway. We expect production to be restored at Winterfell-3 in the first quarter of 2025. Additional development drilling is expected to re-commence in 2025 with the drilling and completion of the Winterfell-4 well, which is expected to be online in the second half of 2025.

The Odd Job Field subsea pump was successfully brought online in July 2024. The project is expected to help sustain long-term production from the Odd Job Field.

The Kodiak #3 infill well located in Mississippi Canyon was brought online in April 2021. The well experienced production issues and was side-tracked. The Kodiak-3ST well was brought online in early September 2022. Well results and initial production were in line with expectations, however well productivity declined thereafter. Workover operations were completed in July 2024 and successfully restored the well productivity.

In October 2023, we announced the Tiberius infrastructure-led exploration well, located in Keathley Canyon Block 964 in the Outer Wilcox play, encountered approximately 75 meters (250 feet) of net oil pay in the primary Wilcox target. Initial fluid and core analysis supports the production potential of the well, with characteristics analogous with similar nearby discoveries in the Wilcox trend. During the first quarter of 2024, Kosmos was awarded five blocks in the Gulf of America Lease Sale 261, including three blocks nearby to our Tiberius discovery. In March 2024, Kosmos completed the acquisition of an additional 16.7% participating interest in the Keathley Canyon Block 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 continues to progress as a phased development with discussions ongoing with our partner to finalize the development plan and timing of a final investment decision.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 25,000 Bopd gross (8,700 Bopd net) for the year ended December 31, 2024.

The Ceiba and Okume Complex workover and infill drilling campaign commenced in the fourth quarter of 2023, completing one production well workover. As a result of safety issues with the drilling rig, the operator terminated the rig contract in early February 2024. In the second quarter of 2024, the partnership secured an alternative rig and drilling contractor to resume the drilling campaign. The infill drilling campaign re-commenced in July 2024 bringing two infill production wells in Block G online in the fourth quarter of 2024. The drilling campaign also included drilling of the S-6 “Akeng Deep” ILX prospect in Block S offshore Equatorial Guinea in the fourth quarter of 2024. The well was drilled to a total vertical depth of approximately 13,225 feet (~4030 meters) and encountered sub-commercial quantities of hydrocarbons. The well has now been plugged and abandoned. The Akeng Deep well marks the end of the 2024 drilling campaign offshore Equatorial Guinea.

In October 2024, Kosmos elected to enter the next phase of the Block S exploration license with a scheduled expiration in December 2025 and no well commitments. The election was approved by the Ministry of Hydrocarbons and Mining Development in December 2024.

In December 2024, we received approval from the Ministry of Hydrocarbons and Mining Development for a twelve month extension to December 2025 for the current exploration phase of Block EG-24.

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

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In the fourth quarter of 2024, the corporate tax rate in Equatorial Guinea was reduced from 35% to 25%, with an effective date of January 1, 2025.

Mauritania and Senegal

Greater Tortue Ahmeyim Project

The Greater Tortue Ahmeyim (GTA) liquefied natural gas (LNG) project achieved first gas production from the subsea system to the FPSO on December 31, 2024. Full commissioning activities of the floating LNG vessel have commenced with first LNG achieved in February 2025. The first LNG cargo is expected in the first quarter of 2025.

On October 7, 2024, the International Chamber of Commerce informed the Company that a final award has been issued in the arbitration proceedings with BP Gas Marketing regarding future LNG sales from GTA Phase 1. The final binding award prohibits the Company from selling LNG cargos to third party buyers during the contract term of the Tortue Phase 1 SPA, which the Company has an option to end in 2033. The final award does not change the terms of the Tortue Phase 1 SPA and is therefore not expected to have an impact on the Company’s long-term expectations and financial condition.

Yakaar and Teranga Discoveries

The Yakaar and Teranga discoveries continue to be progressed as a joint development. During 2023, BP decided not to participate in the development 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%. In March 2024, the current phase of the Cayar Block exploration license was extended an additional two years to July 2026. During 2024, Kosmos completed the concept development work and is now working towards finalizing the partnership to support advancement of the project.

BirAllah and Orca Discoveries

In April 2024, the petroleum contract covering the BirAllah and Orca discoveries offshore Mauritania expired.

Sao Tome and Principe

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

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Results of Operations

All of our results, as presented in the table below, represent operations from Ghana, the Gulf of America, Equatorial Guinea, Mauritania and Senegal. Certain operating results and statistics for the years ended December 31, 2024, 2023 and 2022 are included in the following tables. For a discussion of the year ended December 31, 2023 compared to the year ended December 31, 2022, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2023.

(1)Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.

(2)Includes $93.4 million of oil and gas production costs incurred during 2024 before production commenced at the GTA Phase 1 project in Mauritania and Senegal.

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

Year Ended December 31, 2024 vs. 2023

Oil and gas revenue. Oil and gas revenue decreased by $26.3 million during the year ended December 31, 2024 as compared to the year ended December 31, 2023 primarily as a result of lower average realized oil and gas prices partially offset by increased natural gas sales volumes in Ghana for the year ended December 31, 2024. We sold 23,507 MBoe at an average realized price per barrel of oil equivalent of $71.27 in 2024 and 23,057 MBoe at an average realized price per barrel of oil equivalent of $73.80 in 2023.

Oil and gas production. Oil and gas production costs increased by $140.4 million during the year ended December 31, 2024 as compared to the year ended December 31, 2023 as a result of pre-production operating costs associated with Phase 1 of the GTA project, planned workovers in the Gulf of America business unit and increased production costs in Equatorial Guinea.

Exploration expenses. Exploration expenses increased by $77.6 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023 primarily as a result of approximately $28.0 million related to the S-6 “Akeng Deep” ILX prospect in Block S offshore Equatorial Guinea which encountered sub-commercial quantities of hydrocarbons and was plugged and abandoned in the fourth quarter of 2024 and approximately $37.2 million of previously capitalized costs related to the Asam discovery in Block S offshore Equatorial Guinea that were written off to exploration expense.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $11.8 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023 due to a higher depletion rate per boe in the Gulf of America and Equatorial Guinea business units as a result of the increased cost basis related to the respective development activities in 2024, partially offset by lower depletion in the current year in our TEN Fields due to the impairment loss recorded during the year ended December 31, 2024.

Impairment of long-lived assets. Impairment of long-lived assets decreased $222.3 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023. We recorded an impairment charge of $222.3 million in the year ended December 31, 2023 for the TEN Fields as a result of negative proved oil and gas reserve revisions.

Interest and other financing costs, net. Interest and other financing costs, net decreased by $7.3 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023 primarily as a result of increased capitalized

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interest related to the Greater Tortue Ahmeyim Phase 1 project partially offset by increased interest expenses related to higher interest rates and $25.2 million loss on debt modifications and extinguishments for the year ended December 31, 2024 primarily related to the amendment and restatement of the Facility during the second quarter of 2024 and the repurchase of aggregate principal amounts of the 7.125% Senior Notes, the 7.750% Senior Notes, and the 7.500% Senior Notes during the third quarter of 2024.

Other expenses, net. Other expenses, net decreased $6.0 million during the year ended December 31, 2024, as compared to the year ended December 31, 2023 primarily as a result of approximately $7.4 million of inventory impairments and $7.5 million of other asset write downs in the year ended December 31, 2023 partially offset by an increase in arbitration costs during the year ended December 31, 2024.

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

Liquidity and Capital Resources

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

Oil prices are historically volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This oil price volatility could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program and our current liquidity position is expected to support our capital program for 2025.

As such, our 2025 capital budget is based on our exploitation plans for our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our appraisal and development activities in the Gulf of America, Mauritania and Senegal.

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

In September 2024, we added two new lenders to the Facility syndicate, increasing current total commitments by approximately $145.0 million to the full Facility size and borrowing base capacity 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 $450.0 million. In October 2024, pursuant to a voluntary cancellation notice sent by the Company, the Corporate Revolver was terminated.

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Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2024, 2023 and 2022:

Net cash provided by operating activities. Net cash provided by operating activities in 2024 was $678.2 million compared with net cash provided by operating activities of $765.2 million in 2023 and $1.1 billion in 2022, respectively. The decrease in cash provided by operating activities in the year ended December 31, 2024 when compared to the same period in 2023 is primarily a result of increased oil and gas production costs for the year ended December 31, 2024 as a result of pre-production operating costs associated with Phase 1 of the GTA project, planned workovers in the Gulf of America business unit and increased production costs in Equatorial Guinea, together with lower average realized oil prices, offset by changes in working capital. The decrease in cash provided by operating activities in the year ended December 31, 2023 when compared to the same period in 2022 is primarily a result of lower average realized oil prices.

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The following table presents our liquidity and financial position as of December 31, 2024 and 2023:

(1)When our net leverage ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our net leverage ratio was 2.54x, partially due to pre-production operating costs associated with the Greater Tortue Ahmeyim Phase 1 project. As of December 31, 2024, we expect the payment of interest and fees for the next six-month period on the 7.125% Senior Notes, the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes to be approximately $66.0 million. 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.

Capital Expenditures and Investments

We expect to incur capital costs as we:

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

•completion of the first phase of GTA development; and

•advancing appraisal and development efforts for existing discoveries in the Gulf of America and internationally.

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

2025 Capital Program

We estimate we will spend $400 million or less of capital for the year ending December 31, 2025, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

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•Approximately $275 million related to maintenance activities across our Ghana, Equatorial Guinea and Gulf of America assets, including infill development drilling and facilities integrity spend;

•Approximately $50 million related to the completion of the first phase of the Greater Tortue Ahmeyim development in Mauritania and Senegal;

•Less than $75 million related to progressing our appraisal and development programs in the Gulf of America, Mauritania and Senegal.

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

Significant Sources of Capital

Facility

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

In 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 at June 30, 2024. In September 2024, we added two new lenders to the Facility syndicate, increasing current 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 $450.0 million.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on April 1, 2027, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of December 31, 2029. As of December 31, 2024, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. We were in compliance with the financial covenants contained in the Facility as of September 30, 2024 (the most recent assessment date). 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.

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

Senior Notes

We have four series of senior notes outstanding, which we collectively referred to as the “Senior Notes.” Our 7.125% Senior Notes mature on April 4, 2026, and interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.500% Senior Notes mature on March 1, 2028, and interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 7.750% Senior Notes mature on May 1, 2027, and interest is payable on the 7.750% Senior Notes each May 1 and November 1. In September 2024, the Company issued $500.0 million of 8.750% Senior Notes that mature on October 1, 2031. Interest is payable on the 8.750% Senior Notes each April 1 and October 1.

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

3.125% Convertible Senior Notes due 20230

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

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

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 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 the five business day period after any five 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 than 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.

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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 any 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 shares of our 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 rate 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 case 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 41st 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 we provide notice of redemption, during any 30 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 an 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.

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

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.

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Contractual Obligations

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

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(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of December 31, 2024. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

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

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

(4)In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total remaining commitment to be approximately $137.5 million as of December 31, 2024, net to Kosmos, which will be funded annually by Kosmos over an estimated 12 year period. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.

As of December 31, 2024, we have a commitment to drill one 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 costs. Kosmos’ total share for the two agreements combined currently estimated at approximately $370.0 million, of which $280.1 million has been incurred through December 31, 2024, excluding accrued interest. These amounts are expected to be repaid through the national oil companies’ share of future revenues.

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Critical Accounting Policies

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

Revenue Recognition. We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2024 and 2023, we had no oil and gas imbalances recorded in our consolidated financial statements.

Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a derivative that is separated from the host contract for accounting purposes. The host contract is the receivable from 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 after the sale.

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

Income Taxes. We account for income taxes as required by the ASC 740—Income Taxes (“ASC 740”). We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of changes in tax laws or tax rates, tax credits, and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in no benefit for the deferred tax amounts. As of December 31, 2024 and 2023, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

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

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

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

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

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

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

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

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

•the engineering and geological interpretation of available data;

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

•the accuracy of various mandated economic assumptions; and

•the judgments of the persons preparing the estimates.

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

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

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

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assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted-average cost of capital. Although we base the fair value estimate of each asset group on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserve quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.

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

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

New Accounting Pronouncements

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

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

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

Overview

Kosmos is a full-cycle, deepwater, independent oil and gas exploration and production company focused along the offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea and the U.S. Gulf of Mexico.

Globally, the impacts of Russia’s war in Ukraine, potential instability in the Middle East, a potential recession, inflationary pressures and other varying macroeconomic conditions has impacted supply and demand for oil and gas, which also resulted in significant variability in oil and gas prices. The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on these commodity prices.

Recent Developments

Corporate

In September 2023, the Company repaid the remaining outstanding principal amount of the GoM Term Loan in the amount of $137.5 million plus accrued interest using cash on hand, constituting payment in full. The GoM Term Loan was subsequently terminated pursuant to, and subject to the terms of, the GoM Term Loan.

In September 2023, the Company amended the Facility to accede Kosmos Energy Ghana Investments and Kosmos Energy Ghana Holdings Limited, to the Facility as obligors. As a result, the additional interests in Jubilee and TEN that were acquired in the October 2021 acquisition of Anadarko WCTP are now included when calculating the borrowing base amount for the Facility.

In October 2023, the Company amended the Facility to modify the amortization schedule in order to reduce the number of repayment installments from seven to six equal installments, with the first repayment installment scheduled on October 1, 2024, rather than March 31, 2024. There was no change to the final maturity date or final repayment date.

Ghana

During the year ended December 31, 2023, Ghana production averaged approximately 118,200 Boepd gross (38,600 Boepd net).

The phased development of the Jubilee Field continued during 2023 successfully bringing four production wells and two injection wells online which included three wells (two production wells and one injection well) as part of the successful startup of the Jubilee Southeast project. The Jubilee Southeast project also included the installation of a new subsea production manifold. The development drilling campaign is planned to continue in 2024. One new injection well and one new production well were brought online early in the first quarter of 2024. The partnership expects to bring an additional three wells online in 2024 including two production wells and one injection well before we expect the rig contract to end.

In connection with the approval of the Jubilee Phase 1 PoD in 2009, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to the Government of Ghana at no cost. As of January 1, 2023, the Jubilee partners had fulfilled this commitment. From 2018 through 2022, approximately 19 Bcf of the first 200 Bcf of natural gas was substituted from the TEN Fields in order to maintain consistent gas volumes to shore for Ghana domestic power purposes. Commencing on January 1, 2023, the volume of approximately 19 Bcf of Jubilee gas (in restoration of the amount originally substituted from TEN) was sold to Ghana under the terms of the TAG GSA at $0.50 per MMBtu. During 2023, the Jubilee partners reached an interim agreement to sell Jubilee Field gas at a price of $2.95 per MMBtu to the Government of Ghana beyond the 19 Bcf from the Jubilee Field through May 2024 while the partners continue on-going discussions with the Government of Ghana regarding a long-term future gas sales agreement. During the second quarter of 2023, the operator submitted a draft amended plan of development for TEN, as well as a term sheet for a gas sales agreement covering future gas sales from both the Jubilee and TEN Fields, to the Government of Ghana. If the amended plan of

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development for TEN is delayed or not approved, it could lead to a curtailment or delay of investment and development activity in TEN.

U.S. Gulf of Mexico

During the year ended December 31, 2023, U.S. Gulf of Mexico production averaged approximately 15,400 Boepd (net) (~81% oil).

The Kodiak #3 infill well located in Mississippi Canyon was brought online in April 2021. The well experienced production issues and was shut-in. In March 2022, the Company commenced operations to plug back and side-track the original Kodiak #3 infill well. The Kodiak-3ST well was brought online in early September 2022. Well results and initial production were in line with expectations, however well productivity declined through the end of the third quarter of 2022. Workover plans have been developed and are now expected to commence around the middle of 2024 given the better than forecast performance of the well in 2023.

The Winterfell development project continued to make good progress during 2023 with first oil for Phase 1A of the project targeted for early in the second quarter of 2024 with production from the first two wells. The Winterfell-3 well is expected to commence drilling later in 2024. The host facility production handling agreement and oil export agreements have been executed.

The Odd Job Field subsea pump installation project was approximately 90% complete as of the end of 2023 with an expected online date in the middle of 2024. The project is expected to sustain long-term production from the Odd Job Field.

In July 2023, Kosmos spud the Tiberius infrastructure-led exploration prospect, which is located in Block 964 of Keathley Canyon (33% working interest) in the Outer Wilcox play. In October 2023, we announced the well encountered approximately 75 meters (250 feet) of net oil pay in the primary Wilcox target. Initial fluid and core analysis supports the production potential of the wells, with characteristics analogous with similar nearby discoveries in the Wilcox trend. We are now working with partners on development options for the discovery. During the fourth quarter of 2024, Kosmos was named the apparent high bidder on five blocks in the U.S. Gulf of Mexico Lease Sale 261, including three blocks nearby to our Tiberius discovery.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 25,300 Bopd gross (8,800 Bopd net) for the year ended December 31, 2023.

The 2023 Ceiba Field and Okume Complex development rig campaign commenced in the fourth quarter of 2023. The campaign initially completed one production well workover. However, as a result of safety issues with the drilling rig, the operator terminated the rig contract in early February 2024. The partnership is seeking to secure an alternative rig and drilling contractor to resume the work, which is planned to include the drilling of in-fill production wells in Block G and the Akeng Deep ILX prospect in Block S.

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 of three years from the effective date (March 1, 2023).

In March 2023, we closed a farm-out agreement to sell a 6.0% participating interest in Block S offshore Equatorial Guinea. As a result of the farm-out agreement, Kosmos’ participating interest in Block S was reduced to 34.0%.

Mauritania and Senegal

Greater Tortue Ahmeyim Unit

Phase 1 of the Greater Tortue project continued to progress in 2023. The following milestones were achieved through the year-end and filing date:

•Drilling: The operator has successfully drilled and completed all four wells with expected production capacity significantly higher than what is required for first gas.

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•Hub Terminal: Construction work is complete, and handover to operations was completed in August 2023.

•Subsea: Significant progress has been made on the installation of the infield flowlines and subsea structures. Work re-commenced in the fourth quarter of 2023 with completion expected at the end of the second quarter of 2024. BP, on behalf of the partner group, has initiated the process under its agreement with the original subsea contractor to recover the losses incurred. The partnership will seek to recover the maximum recoverable damages in binding arbitration. We estimate Kosmos’ net share of the recoverable damages to be up to $160.0 million.

•FLNG: The FLNG construction was completed in the fourth quarter of 2023 and the vessel arrived on location offshore Mauritania/Senegal in the first quarter of 2024. Hookup work is now underway.

•FPSO: The vessel is currently in a shipyard in Tenerife for inspection and repair of fairleads. Completion of this work and transit to the project site is expected early in the second quarter of 2024 ahead of final hookup and commissioning.

The critical path to first gas on Phase 1 of the Greater Tortue Ahmeyim project, now targeted in the third quarter of 2024, continues to be through the arrival, hookup and commissioning of the FPSO. Timely execution of this workstream is expected to allow for first LNG in the fourth quarter of 2024.

Yakaar and Teranga Discoveries

The Yakaar and Teranga discoveries continue to be analyzed as a joint development. During 2023, we continued progressing appraisal studies, maturing concept design, and proposed to partners that the Yakaar and Teranga discoveries in the Cayar Offshore Profond Block be pursued as a commercial joint development. PETROSEN agreed to the proposal, however, BP decided not to participate in the 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 now: 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%.

Sao Tome and Principe

In the second quarter of 2023, we received approval for a twelve month extension to May 2024 for the current exploration phase for Block 5 offshore Sao Tome and Principe.

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Results of Operations

All of our results, as presented in the table below, represent operations from Ghana, the U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the years ended December 31, 2023, 2022 and 2021 are included in the following tables. For a discussion of the year ended December 31, 2022 compared to the year ended December 31, 2021, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022.

(1)Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the acquisition date.

(2)Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.

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

Year Ended December 31, 2023 vs. 2022

(1)Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.

Oil and gas revenue. Oil and gas revenue decreased by $543.7 million during the year ended December 31, 2023 as compared to the year ended December 31, 2022 primarily as a result of lower average oil prices and lower oil production across our portfolio due to natural field decline, partially offset by increased natural gas sales in Ghana for the year ended December 31, 2023. We sold 23,057 MBoe at an average realized price per barrel of oil equivalent of $73.80 in 2023 and 23,117 MBoe at an average realized price per barrel of oil equivalent of $97.13 in 2022.

Gain on sale of assets. During the fourth quarter of 2022, we received $50.0 million from Shell under the terms of our 2020 farm-out agreement.

Oil and gas production. Oil and gas production costs decreased by $13.0 million during the year ended December 31, 2023 as compared to the year ended December 31, 2022 as a result of changes to the production mix across our portfolio.

Exploration expenses. Exploration expenses decreased by $92.0 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022 primarily as a result of the $64.2 million of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania that were written off to exploration expense with the expiration of the exploration period of Block C8 during the year ended December 31, 2022, along with $13.7 million of exploration expense recorded in 2022 related to two abandoned Ntomme step out wells in Ghana.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $53.3 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022 as a result of lower depletion per barrel in the current year resulting from a lower cost basis in our TEN Fields due to the impairment loss recorded in the year ended December 31, 2022.

Impairment of long-lived assets. Impairment of long-lived assets decreased $227.7 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022. We recorded an impairment charge of $450.0 million

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in the year ended December 31, 2022 for the TEN Fields as a result of negative proved oil and gas reserve revisions. We recorded an additional impairment charge on the TEN Fields during 2023 of $222.3 million based on further negative revisions to proved oil and gas reserves associated with the TEN Fields. The additional revisions were primarily driven by a change in the partnership’s development work scope for the TEN Fields and well performance.

Interest and other financing costs, net. Interest and other financing costs, net decreased by $22.4 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022 primarily as a result of increased capitalized interest related to the Greater Tortue Ahmeyim project partially offset by increased interest expenses related to higher interest rates.

Derivatives, net. During the years ended December 31, 2023 and 2022, we recorded a loss of $11.1 million and $260.9 million, respectively, on our outstanding hedge positions. The changes recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net increased $32.7 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022 primarily as a result of approximately $7.4 million of inventory impairments and $7.5 million of other asset write downs in the year ended December 31, 2023 and $11.9 million of insurance proceeds in the year ended December 31, 2022.

Income tax expense (benefit). For the years ended December 31, 2023 and December 31, 2022, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate, jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.

Liquidity and Capital Resources

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

Oil prices are historically volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could result in wide fluctuations in future oil prices, which could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program and our current liquidity position is expected to support our capital program for 2024.

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

In October 2023, during the Fall 2023 redetermination, the Company’s lending syndicate approved a borrowing base for the facility of $1.25 billion increasing undrawn availability. As of December 31, 2023, borrowings under the Facility totaled $925.0 million and the undrawn availability under the facility was $325.0 million. As of December 31, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million.

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Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2023, 2022 and 2021:

Net cash provided by operating activities. Net cash provided by operating activities in 2023 was $765.2 million compared with net cash provided by operating activities of $1.1 billion in 2022 and $374.3 million in 2021, respectively. The decrease in cash provided by operating activities in the year ended December 31, 2023 when compared to the same period in 2022 is primarily a result of lower average realized oil prices. The increase in cash provided by operating activities in the year ended December 31, 2022 when compared to the same period in 2021 is primarily a result of higher realized oil prices and increased production.

The following table presents our liquidity and financial position as of December 31, 2023 and 2022:

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Capital Expenditures and Investments

We expect to incur capital costs as we:

•drill additional infill wells and execute exploitation and production activities in Ghana, Equatorial Guinea and the U.S. Gulf of Mexico;

•execute appraisal and development activities in Ghana, the U.S. Gulf of Mexico, Mauritania and Senegal; and

•execute infrastructure-led exploration and appraisal efforts in the U.S. Gulf of Mexico and Equatorial Guinea.

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

2024 Capital Program

We estimate we will spend approximately $700-$750 million of capital for the year ending December 31, 2024, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

•Approximately $250-$300 million related to maintenance activities across our Ghana, Equatorial Guinea and U.S. Gulf of Mexico assets, including infill development drilling and integrity spend;

•Approximately $350-$400 million related to the development of Phase 1 of Greater Tortue Ahmeyim in Mauritania and Senegal and Winterfell in the U.S. Gulf of Mexico;

•Approximately $50-$100 million related to progressing our infrastructure-led exploration and appraisal programs in the U.S. Gulf of Mexico, including Tiberius appraisal activities, and the drilling of the ILX prospect Akeng Deep in Equatorial Guinea, as well as the appraisal plans of our greater gas resources in Mauritania and Senegal, including Phase 2 of Greater Tortue Ahmeyim, Yakaar-Teranga and BirAllah.

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

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Significant Sources of Capital

Facility

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

In October 2023, during the Fall 2023 redetermination, the Company’s lending syndicate approved a borrowing base of $1.25 billion. As of December 31, 2023, borrowings under the Facility totaled $925.0 million and the undrawn availability under the facility was $325.0 million.

On November 23, 2022, the Company amended the Facility to update the interest rate benchmark from LIBOR to term SOFR, to be effective as of April 19, 2023. On September 29, 2023, the Company amended the Facility to accede Kosmos Energy Ghana Investments and Kosmos Energy Ghana Holdings Limited to the Facility as obligors. As a result, the additional interests in Jubilee and TEN that were acquired in the October 2021 acquisition of Anadarko WCTP are now included when calculating the borrowing base amount for the Facility, effective as of October 1, 2023. On October 19, 2023, the Company amended the Facility to modify the amortization schedule in order to reduce the number of repayment installments from seven to six equal installments, with the first repayment installment scheduled on October 1, 2024, rather than March 31, 2024. There was no change to the final maturity date or final repayment date.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on October 1, 2024, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2027. As of December 31, 2023, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. We were in compliance with the financial covenants contained in the Facility as of September 30, 2023 (the most recent assessment date). The Facility contains customary cross default provisions.

Corporate Revolver

The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. On November 23, 2022, the Company amended the Corporate Revolver to update the interest rate benchmark from compounded SOFR to term SOFR. As of December 31, 2023, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million.

The available amount is not subject to borrowing base constraints. We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.

We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2023 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

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

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Senior Notes

We have three series of senior notes outstanding, which we collectively referred to as the “Senior Notes.” Our 7.125% Senior Notes mature on April 4, 2026, and interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.500% Senior Notes mature on March 1, 2028, and interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 7.750% Senior Notes mature on May 1, 2027, and interest is payable on the 7.750% Senior Notes each May 1 and November 1.

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

GoM Term Loan

In September 2020, the Company entered into a five-year $200 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. On September 15, 2023, the Company repaid the remaining outstanding principal amount of $137.5 million plus accrued interest using cash on hand, constituting payment in full. The GoM Term Loan was subsequently terminated pursuant to, and subject to the terms of, the GoM Term Loan.

Contractual Obligations

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

______________________________________

(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of December 31, 2023. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.

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

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

We have a commitment to drill three development wells and one exploration well in Equatorial Guinea. We have a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Greater Tortue FPSO.

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 development costs. Kosmos’ total share for the two agreements combined originally estimated at approximately $300.0 million, of which $259.2 million has been incurred through December 31, 2023, excluding accrued interest. These amounts are expected to be repaid through the national oil companies’ share of future revenues.

Critical Accounting Policies

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

Revenue Recognition. We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2023 and 2022, we had no oil and gas imbalances recorded in our consolidated financial statements.

Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a derivative that is required to be 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 after the sale.

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

Income Taxes. We account for income taxes as required by the ASC 740—Income Taxes (“ASC 740”). We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and

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liabilities at the end of each period as well as the effects of changes in tax laws or tax rates, tax credits, and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in no benefit for the deferred tax amounts. As of December 31, 2023 and 2022, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

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

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

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

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

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

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

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

Estimates of Proved Oil and Natural 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 natural 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. As additional proved reserves are discovered, reserve quantities and future cash flows will be estimated by independent petroleum consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:

•the engineering and geological interpretation of available data;

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

•the accuracy of various mandated economic assumptions; and

•the judgments of the persons preparing the estimates.

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

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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.

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

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

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

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

New Accounting Pronouncements

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

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

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

Overview

Kosmos is a full-cycle, deepwater, independent oil and gas exploration and production company focused along the offshore Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as world-class gas projects offshore Mauritania and Senegal. We also pursue a proven basin exploration program in Equatorial Guinea and the U.S. Gulf of Mexico.

Globally, the impacts of Russia’s invasion of Ukraine, a potential recession, COVID-19 and other varying macroeconomic conditions has impacted supply and demand for oil and gas, which also resulted in significant variability in oil and gas prices. The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on these commodity prices.

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Recent Developments

Corporate

In March 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement. The new revolving credit facility decreases the borrowing capacity from $400 million to $250 million and extends the maturity date from May 2022 to the end of 2024. In anticipation of the cessation of the LIBOR, as part of the refinancing, interest for the Corporate Revolver was linked to the SOFR administered by the Federal Reserve Bank of New York. The Company expects the reduced borrowing capacity of the Corporate Revolver to offset an increase in the margin, resulting in slightly lower interest expenses going forward. In November 2022, we amended the Corporate Revolver and the Facility to update the interest rate benchmark under the Facility from LIBOR to term SOFR and to update the interest rate benchmark under the Corporate Revolver from compounded SOFR to term SOFR, each change to be effective as of April 19, 2023. The Corporate Revolver was also amended to reflect that The Standard Bank of South Africa Limited has been appointed as the new Facility Agent.

Under the terms of our 2020 farm-out agreement with Shell, potential contingent consideration is payable by Shell depending on the results of the first four exploration wells Shell drills in the purchased assets, excluding South Africa. Upon approval of the relevant operating committee of an appraisal plan for submission to the relevant governmental authority for any of those first four exploration wells, Shell will be required to pay Kosmos $50.0 million of consideration for each discovery for which an appraisal plan is approved by the relevant operating committee, capped in the aggregate at a maximum of $100.0 million total. During the fourth quarter of 2022, we received formal notice from Shell that an appraisal plan for one of the first four exploration wells had been submitted under the terms of Shell’s Petroleum Agreement with Namibia. As a result, we received additional proceeds of $50.0 million from Shell in the fourth quarter of 2022 related to the transaction.

Ghana

During the year ended December 31, 2022, Ghana production averaged approximately 107,200 Bopd gross (36,300 Bopd net). Jubilee production averaged approximately 83,600 Bopd gross (31,300 Bopd net) and TEN production averaged approximately 23,600 Bopd gross (5,000 Bopd net).

The multi-year development drilling program in Ghana continued to progress in 2022 with the successful drilling and completion of one producer well and two water injector wells in the Jubilee Field (all successfully brought online during 2022) and the completion of one water injector well and one producer well at TEN (both successfully brought online during 2022). During 2022, the partnership drilled two new riser base wells at TEN to further define the extent of the Ntomme reservoir supporting potential future TEN development. The first well was drilled to test two separate reservoir objectives and encountered better reservoir quality and thickness than expected but was water bearing. In October 2022, a second well targeting a different fairway was drilled. The well encountered approximately 5 meters of net oil pay with poorer than expected reservoir quality. Both wells have been plugged and abandoned. The partnership will continue to evaluate the full results of the two wells to high-grade and optimize the future drilling plans for TEN. In the fourth quarter of 2022, drilling operations commenced on the Jubilee Southeast project, successfully drilling two wells, with a third drilled in January 2023. The three wells consisted of two producer wells and one water injector well. The two producer wells are expected online in the middle of 2023.

In July 2022, the Jubilee partners completed the transition of the operations & maintenance (O&M) services for the Jubilee FPSO from external provider MODEC, Inc. to Tullow.

Following the closing of the acquisition of Anadarko WCTP Company (“Anadarko WCTP”) in the fourth quarter of 2021, Kosmos’ interest in the Jubilee Unit Area and the TEN fields offshore Ghana were 42.1% and 28.1%, respectively. 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”) and PetroSA 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 governmental 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 was treated as a recovery of cost and normal retirement, which resulted in no gain or loss being recognized.

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In connection with the approval of the Jubilee Phase 1 PoD in 2009, the Jubilee Field partners agreed to provide the first 200 Bcf of natural gas produced from the Jubilee Field Phase 1 development to the Government of Ghana at no cost. As of January 1, 2023, the Jubilee partners have fulfilled this commitment, providing 200 Bcf of natural gas to the Government of Ghana. From 2018 through 2022, approximately 19 Bcf of the first 200 Bcf of natural gas was substituted from the TEN fields in order to maintain consistent gas volumes to shore for Ghana domestic power purposes. Effective January 1, 2023, the volume of approximately 19 Bcf of Jubilee gas (in restoration of the amount originally substituted from TEN) will be sold to Ghana under the terms of the TAG GSA at $0.50 per mmbtu over a period of approximately six months. The Jubilee and TEN partners are currently in discussions with the Government of Ghana regarding a future gas sales agreement.

U.S. Gulf of Mexico

During the year ended December 31, 2022, U.S. Gulf of Mexico production averaged approximately 17,400 Boepd (net) (~83% oil). Production for the fourth quarter of 2022 was impacted by planned and unplanned facilities shutdowns as well as loop currents in the Gulf of Mexico.

In March 2022, the Company commenced operations to plug back and side-track the original Kodiak-3 infill well located in Mississippi Canyon. The well was sidetracked, and the Kodiak-3ST well was brought back online in early September 2022, with insurance proceeds covering a substantial portion of the costs incurred to return the well to production. Well results and initial production were in line with expectations, however well productivity declined through the end of the fourth quarter of 2022 and workover plans have been developed for remediation in the second half of 2023.

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. As a result of the transaction, our working interest increased from 29.1% to 35.0%.

In January 2021, we announced the Winterfell-1 exploration well encountered approximately 26 meters (85 feet) of net oil pay in two intervals. The Winterfell-1 well was designed to test a sub-salt Upper Miocene prospect located in Green Canyon Block 944. In January 2022, the Winterfell-2 appraisal well in Green Canyon Block 943 was drilled to evaluate the adjacent fault block to the northwest of the original Winterfell discovery and was designed to test two horizons that were oil bearing in the Winterfell-1 well, with an exploration tail into a deeper horizon. The well discovered approximately 40 meters (120 feet) of net oil pay in the first and second horizons with better oil saturation and porosity than pre-drill expectations. The exploration tail discovered an additional oil-bearing horizon in a deeper reservoir which is also prospective in the blocks immediately to the north. During the third quarter of 2022, the Field Development Plan for the Winterfell field was approved by all partners and a drilling rig was secured by Beacon, the operator of the Winterfell field, to undertake the development drilling, including the sidetrack and completion of the Winterfell-1 well, completion of the Winterfell-2 well and drilling and completion of the Winterfell-3 well in an adjacent fault block to the southeast of the Winterfell-1 discovery well as part of the Field Development Plan. The Winterfell development project continues to make progress. Drilling of the wells for the first phase of the development is expected to start in the third quarter of 2023 with first production for the project targeted to be around the end of the first quarter of 2024. Host facility production handling and midstream export agreements are expected to be completed and signed within the next several months.

In March 2022, Kosmos completed the acquisition of an additional 5.5% interest in the Winterfell area in Green Canyon Blocks 943, 944, 987 and 988 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 the two 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 now 37.8%.

In June 2022, we executed, as operator of the Odd Job field, a contract for $131.6 million (gross) with Subsea 7 (US) LLC and OneSubsea LLC to fabricate and install a subsea pump in the Odd Job field. The project commenced in July 2022 with an expected online date around the middle of 2024. Kosmos’ average working interest in the Odd Job field is approximately 54.9%.

In the second half of 2023, Kosmos plans to drill the Tiberius infrastructure-led exploration prospect, which is located in block 964 of Keathley Canyon (33% working interest) in the prolific outer Wilcox play.

Equatorial Guinea

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Production in Equatorial Guinea averaged approximately 30,900 Bopd gross (9,900 Bopd net) for the year ended December 31, 2022.

In May 2022, Kosmos and its Joint Venture partners agreed with the Ministry of Mines and Hydrocarbons of Equatorial Guinea to extend the Block G petroleum contract term harmonizing the expiration of the Ceiba Field and Okume Complex production licenses (from 2029 and 2034 respectively) to 2040. The license extensions support the next phase of investment in the licenses. As part of the extension, during the second quarter of 2022, Kosmos paid a signature bonus and agreed to undertake a future work program including the drilling of three development wells on Block G in either the Ceiba Field or Okume Complex and the drilling of one exploration well in Block S offshore Equatorial Guinea.

In August 2022, the partnership entered into a drilling rig contract for the next drilling campaign, which is expected to commence in the second half of 2023. The first well is expected to be online by the end of the fourth quarter of 2023 with subsequent wells online early in 2024.

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 will result in our participating interest in Block S reducing to 34.0%. The transaction is awaiting governmental approvals. During the fourth quarter of 2022, we received approval from the Government of Equatorial Guinea to enter the second sub-period phase of the Block S exploration license with a scheduled expiration in December 2024. During 2023, Kosmos and partners plan to progress the infrastructure-led exploration prospect, Akeng Deep in Block S for drilling in early 2024.

In December 2022, we received approval from the Government of Equatorial Guinea for a two year extension to the current exploration phase for Block EG-21 offshore Equatorial Guinea through December 2024. Kosmos currently holds an 80% participating interest in Block EG-21.

In December 2022, we received approval from the Government of Equatorial Guinea to enter the second exploration sub-period for Block EG-24 offshore Equatorial Guinea which has a scheduled expiration in December 2024 and no well commitments.

Mauritania and Senegal

In June 2022, the exploration period of Block C8 offshore Mauritania expired. In October 2022, the partnership and the government of Mauritania executed a new Production Sharing Contract (“PSC”) covering the BirAllah and Orca discoveries, which were previously included in the former Block C8 PSC. The new PSC provides up to thirty months to submit a development plan covering the BirAllah and/or Orca discoveries with the terms of the new PSC substantially similar to the former PSC for Block C8 with additional provisions for enhanced back-in rights for the Government of Mauritania, local content, SMH’s capacity building and an environmental fund. Kosmos’ participating interest in the new PSC is 28.0% and full election by SMH of their back-in rights would reduce Kosmos’ participating interest to approximately 22.1%.

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

Greater Tortue Ahmeyim Unit

Phase 1 of the Greater Tortue project continued to make good progress in 2022 with first gas for the project targeted to be in the fourth quarter of 2023. The following milestones were achieved through the year-end and filing date:

•FLNG: on track for sailaway in second quarter of 2023 as construction, mechanical completion activities, and commissioning work continues.

•FPSO: On January 20, 2023, the FPSO vessel departed the COSCO shipyard in Qidong, China. It has begun its 12,000 nautical mile journey to its final destination offshore Mauritania/Senegal, after first making a stop in Singapore. Once on location, its final stage of hookup and commissioning work is expected to commence.

•Hub Terminal: As its construction is complete, work is focused on progressing the final hookup and commissioning and preparing it for the integration into the other project elements.

•Subsea: The infield umbilical installation and 70% of the pipelay have been completed. Work is focused on completing the remaining flowline installation and completing the subsea structures currently under construction.

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•Drilling: successfully drilled and completed all four wells and demobilized the rig in February 2023. Expected production capacity is significantly more than what is required for first gas.

On Phase 2 of the Greater Tortue Ahmeyim LNG project, the partners (SMH, Petrosen, BP and Kosmos) have confirmed the development concept and will progress a gravity-based structure (GBS) with total capacity of between 2.5-3.0 million tonnes per annum. GBS LNG developments have a static connection to the seabed with the structure base providing LNG storage and a foundation for liquefaction facilities. The concept design will also include new wells and subsea equipment, maximizing the use of existing Phase 1 infrastructure. In July 2021, the Greater Tortue Ahmeyim project was granted the status of ‘National Project of Strategic Importance’ by the Presidents of Mauritania and Senegal, demonstrating the commitment of the host governments and the significance of the project to both countries.

Sao Tome and Principe

In the second quarter of 2022, we received approval for a six month extension to May 2023 for the current exploration phase for Block 5 offshore Sao Tome and Principe.

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Results of Operations

All of our results, as presented in the table below, represent operations from the Jubilee and TEN fields in Ghana, the U.S. Gulf of Mexico and Equatorial Guinea. Certain operating results and statistics for the years ended December 31, 2022, 2021 and 2020 are included in the following tables. For a discussion of the year ended December 31, 2021 compared to the year ended December 31, 2020, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2021.

(1)Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the acquisition date.

(2)Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.

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

Year Ended December 31, 2022 vs. 2021

(1)Includes activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the acquisition date.

(2)Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.

Oil and gas revenue. Oil and gas revenue increased by $913.3 million during the year ended December 31, 2022 as compared to the year ended December 31, 2021 as a result of higher production rates at Jubilee and our acquisition of additional interests in Ghana during the fourth quarter of 2021 which drove increased sales volumes in Ghana as well as higher average oil prices. We sold 23,117 MBoe at an average realized price per barrel of oil equivalent of $97.13 in 2022 and 19,850 MBoe at an average realized price per barrel of oil equivalent of $67.10 in 2021.

Gain on sale of assets. During the fourth quarter of 2022, we received $50.0 million from Shell under the terms of our 2020 farm-out agreement.

Oil and gas production. Oil and gas production costs increased by $57.1 million during the year ended December 31, 2022 as compared to the year ended December 31, 2021 as a result of our acquisition of additional interests and sales volumes in Ghana.

Exploration expenses. Exploration expenses increased by $68.8 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021 primarily as a result of the $64.2 million of previously capitalized costs related to the BirAllah and Orca discoveries incurred under the Block C8 license offshore Mauritania that were written off to exploration expense in 2022 with the expiration of the exploration period of Block C8, approximately $15.8 million related to the exit of leases in the U.S. Gulf of Mexico and Mauritania business units in 2022, and approximately $13.7 million of

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exploration expense recorded in 2022 related to two abandoned Ntomme step out wells compared to the 2021 activity including the Zora exploration well, which did not find hydrocarbons and was plugged and abandoned in August 2021 with $14.1 million of well costs charged to exploration expense in 2021.

General and administrative. General and administrative costs increased by $9.3 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021 primarily as a result of increased compensation and benefits, travel costs and professional fees during the year ended December 31, 2022.

Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $31.0 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021 as a result of higher sales volumes in the current year.

Impairment of long-lived assets. Impairment of long-lived assets increased $450.0 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021 as a result of a negative proved oil and gas reserve revision at TEN, primarily driven by recent well performance, which resulted in impairment charges of $450.0 million for the year ended December 31, 2022.

Interest and other financing costs, net. Interest and other financing costs, net decreased by $10.1 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021 primarily as a result of $15.2 million for loss on extinguishment of debt during 2021 related to the Facility amendment, $4.4 million loss on extinguishment of debt during 2021 related to the Bridge Notes and increased capitalized interest in 2022 related to the Greater Tortue Ahmeyim project, offset by increased interest expense on the 7.750% Senior Notes and the 7.500% Senior Notes and guarantee fees on the Greater Tortue FPSO transaction.

Derivatives, net. During the years ended December 31, 2022 and 2021, we recorded a loss of $260.9 million and $270.2 million, respectively, on our outstanding hedge positions. The changes recorded were a result of changes in the forward curve of oil prices during the respective periods.

Other expenses, net. Other expenses, net decreased $19.2 million during the year ended December 31, 2022, as compared to the year ended December 31, 2021 primarily as a result of $7.0 million insurance settlements and approximately $3.0 million gain on asset retirement obligations.

Income tax expense (benefit). For the years ended December 31, 2022 and December 31, 2021, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets and other non-deductible expenses, primarily in the U.S.

Liquidity and Capital Resources

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

Oil prices are historically volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could result in wide fluctuations in future oil prices, which could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program, partner carries and our current liquidity position support our capital program for 2023.

As such, our 2023 capital budget is based on our exploitation and production plans for Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, our infrastructure-led exploration and appraisal program in the U.S. Gulf of Mexico and Equatorial Guinea, and our appraisal and development activities in the U.S. Gulf of Mexico, Mauritania and Senegal.

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

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In March 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement. The total size of the Corporate Revolver reduced from $400 million to $250 million and the maturity date extended from May 2022 to December 31, 2024.

In October 2022, during the Fall 2022 redetermination, the Company’s lending syndicate approved a borrowing base for the facility of approximately $1.24 billion. As of December 31, 2022, borrowings under the Facility totaled $625.0 million and the undrawn availability under the facility was $618.0 million.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2022, 2021 and 2020:

Net cash provided by operating activities. Net cash provided by operating activities in 2022 was $1.1 billion compared with net cash provided by operating activities of $374.3 million in 2021 and $196.1 million in 2020, respectively. The increase in cash provided by operating activities in the year ended December 31, 2022 when compared to the same period in 2021 is primarily a result of increased oil prices and increased production. The increase in cash provided by operating activities in the year ended December 31, 2021 when compared to the same period in 2020 is primarily a result of higher oil prices.

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The following table presents our liquidity and financial position as of December 31, 2022 and 2021:

Capital Expenditures and Investments

We expect to incur capital costs as we:

•drill additional infill wells and execute exploitation and production activities in Ghana, Equatorial Guinea and the U.S. Gulf of Mexico;

•execute appraisal and development activities in Ghana, the U.S. Gulf of Mexico, Mauritania and Senegal; and

•execute infrastructure-led exploration and appraisal efforts in the U.S. Gulf of Mexico and Equatorial Guinea.

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

2023 Capital Program

We estimate we will spend approximately $700-$750 million of capital for the year ending December 31, 2023, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:

•Approximately $250-$300 million related to maintenance activities across our Ghana, Equatorial Guinea and U.S. Gulf of Mexico assets, including infill development drilling and integrity spend

•Approximately $350-$400 million related to the developments of Jubilee Southeast in Ghana, Phase 1 of Greater Tortue Ahmeyim in Mauritania and Senegal, and Winterfell in the U.S. Gulf of Mexico

•Approximately $50-$100 million related to progressing our infrastructure-led exploration and appraisal programs in the U.S. Gulf of Mexico and Equatorial Guinea, as well as the appraisal plans of our greater gas

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resources in Mauritania and Senegal, including Phase 2 of Greater Tortue Ahmeyim, BirAllah and Yakaar-Teranga.

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

Significant Sources of Capital

Facility

The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets’ reserves and/or resources in the Jubilee and TEN fields in Ghana and the Ceiba and Okume fields in Equatorial Guinea, however, excludes the additional interests in Jubilee and TEN acquired in the October 2021 acquisition of Anadarko WCTP.

In October 2022, during the Fall 2022 redetermination, the Company’s lending syndicate approved a borrowing base of approximately $1.24 billion. As of December 31, 2022, borrowings under the Facility totaled $625.0 million and the undrawn availability under the facility was $618.0 million. On November 23, 2022, the Company amended the Facility to update the interest rate benchmark from LIBOR to term SOFR, to be effective as of April 19, 2023.

The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2024, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2027. As of December 31, 2022, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.

If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain asset. We were in compliance with the financial covenants contained in the Facility as of September 30, 2022 (the most recent assessment date). 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 resulting in the following changes to the terms:

•The total size of the Corporate Revolver is reduced from $400 million to $250 million.

•The maturity date is extended from May 2022 to December 31, 2024.

•Borrowings under the Corporate Revolver now bear interest at a rate equal to SOFR administered by the Federal Reserve Bank of New York plus a credit adjustment spread plus a 7.0% margin plus mandatory costs, if applicable.

•Addition of a negative pledge covenant over the participating interests held by the Company’s wholly-owned subsidiary, Kosmos Energy Ghana Investments, in the WCTP and DT blocks offshore Ghana.

•As the Corporate Revolver is intended to continue to largely remain undrawn, the Company is required to use the proceeds from any capital markets and loan transactions to first repay any drawn outstanding balance under the Corporate Revolver and the Company is subject to a cash sweep of at least 50% of the Company’s Excess Cash (as defined in the Corporate Revolver) to pay outstanding balances, if any, as of March 31 or September 30 in any calendar year.

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The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. The Company expects the reduced Corporate Revolver size to offset an increase in the margin, resulting in slightly lower interest expenses going forward. On November 23, 2022, the Company amended the Corporate Revolver to update the interest rate benchmark from compounded SOFR to term SOFR, to be effective as of April 19, 2023, and to reflect that The Standard Bank of South Africa Limited has been appointed as the new Facility Agent. As of December 31, 2022, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was $250.0 million.

The available amount is not subject to borrowing base constraints. We have the right to cancel all the undrawn commitments under the Corporate Revolver. We are required to repay certain amounts due under the Corporate Revolver with sales of certain subsidiaries or sales of certain assets. If an event of default exists under the Corporate Revolver, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Corporate Revolver over certain assets held by us.

We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2022 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions.

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

Senior Notes

We have three series of senior notes outstanding, which we collectively referred to as the “Senior Notes.” Our 7.125% Senior Notes mature on April 4, 2026, and interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.500% Senior Notes mature on March 1, 2028, and interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 7.750% Senior Notes mature on May 1, 2027, and interest is payable on the 7.750% Senior Notes each May 1 and November 1.

The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equally in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility and the GoM Term Loan). The Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets and the interests acquired in the Anadarko WCTP Acquisition, and on a subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.

GoM Term Loan

In September 2020, the Company entered into a five-year $200 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with net proceeds received of $197.7 million after deducting fees and other expenses. The GoM Term Loan also includes an accordion feature providing for incremental commitments of up to $100 million subject to certain conditions. As of December 31, 2022, borrowings under the GoM Term Loan totaled $145 million.

The GoM Term Loan contains customary affirmative and negative covenants, including covenants that affect our ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or capital expenditures, among other things. The GoM Term Loan is guaranteed on a senior, secured basis by certain subsidiaries owning the Company's U.S. Gulf of Mexico assets.

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

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Contractual Obligations

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