Kosmos Energy Ltd.
For the period ended Dec 31, 2025. Filed Mar 2, 2026.
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A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Mar 2, 2026
KOS$2.11-4.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-24.
0001509991-25-000026
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-03-02.
0001509991-26-000017
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 136 previous paragraphs and 135 current paragraphs.
68 unchanged; 30 reworded; 37 added; 37 removed; 1 previous and 0 current paragraphs rearranged.
Tables are not compared: 5 previous and 5 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (37)
Current report
On September 24, 2025, the Company entered into a senior secured term loan credit agreement secured by first priority liens on all of the Company’s Gulf of America assets (as defined in the Credit Agreement). The GoA Term Loan Facility is a four-year term loan structured into two tranches, with the first tranche a principal amount of $150.0 million, which was funded in October 2025, and a second tranche of an additional $100.0 million, which was funded in January 2026. The net proceeds were used, together with cash on hand, to fund the redemption of the 7.125% Senior Notes due 2026 totaling $250.0 million in aggregate. The GoA Term Loan Facility is now fully drawn and matures in 2029, with principal payments beginning June 30, 2026.
Current report
On January 16, 2026, the Company announced the pricing of $350.0 million aggregate principal amount of 11.250% senior secured bonds due 2031 in the Nordic market (the “GTA Nordic bonds”). The GTA Nordic bonds are fully and unconditionally guaranteed by the Company, as well as the Company’s wholly-owned subsidiaries that own the Mauritania and Senegal assets. In February 2026, Kosmos used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of its 7.750% Senior Notes due 2027 and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility, with the remaining proceeds to be used for future retirements of the 7.750% Senior Notes due 2027.
Current report
In July 2025, new U.S. tax legislation was signed into law in the United States known as the “One Big Beautiful Bill Act” or “OBBBA”. The legislation includes a broad range of U.S. corporate tax reform provisions affecting businesses across numerous industries. The necessary adjustments have been reflected for the year ended December 31, 2025. Based on our evaluation, we have determined that the impact of OBBBA is not material to the Company’s financial position or results.
Current report
The partnership completed a new 4D seismic survey on the Jubilee and TEN Fields during the first quarter of 2025 and an Ocean Bottom Node survey was completed in the fourth quarter of 2025. In the second quarter of 2025, we commenced the next development drilling campaign in the Jubilee Field. The Jubilee drilling progressed during the year bringing one producer well successfully online in July 2025. After undergoing scheduled maintenance, the rig returned to the Jubilee Field to drill an additional producer well, which was successfully completed and brought online in January 2026. The development drilling campaign will continue in 2026 by drilling four planned producer wells and an additional water injector well.
Current report
In June 2025, the Jubilee and TEN partnerships entered into a Memorandum of Understanding with the Government of Ghana to extend to 2040 the WCTP and the DT licenses, which cover the Jubilee and TEN fields offshore Ghana. The Ghana partnership received Government approval in December 2025 for the license extensions. Accordingly, the WCTP and DT licenses have been extended to 2040 and starting from July 2036, Ghana National Petroleum Corporation’s share in the fields will increase by an additional 10% interest and the joint venture partners’ shares will decrease pro rata. As part of the extension of the Petroleum Agreements, the Jubilee plan of development is amended to include up to twenty additional wells in the fields. Additionally, in December 2025, as part of the extension of the WCTP and DT Petroleum Agreements, the Ghana partners and
Current report
Government of Ghana have approved an amended gas sales agreement at a price of $2.50 per MMBtu through the extended expiration date of 2040 for the WCTP and DT licenses.
Current report
In February 2026, the TEN partnership executed the final Sale and Purchase Agreement to acquire the TEN FPSO from MODEC, Inc. at the end of its current lease in 2027 for a gross purchase price of $205.0 million.
Current report
On Tiberius, Kosmos (operator, 50% working interest) continues to progress the development plan with our partner Occidental Petroleum Corporation (“Oxy”) (50% working interest). A production handling agreement for the Oxy-operated Lucius platform was signed in the third quarter of 2025. A final investment decision and farm down to reduce Kosmos’ working interest is expected in 2026.
Current report
In January 2026, Kosmos was awarded two lease blocks in the Gulf of America Big Beautiful Gulf Lease Sale 1 (“BBG1”).
Current report
At Winterfell, in October 2024, shortly after startup of the Winterfell-3 well, production at the field was curtailed due to sand production from the Winterfell-3. Production from the first two wells was restored in December 2024. Remediation work on Winterfell-3 was performed in the first quarter of 2025, however, it was unsuccessful. Winterfell-3 was temporarily plugged and abandoned during the first quarter of 2025 while the partnership evaluated options to restore production from the Winterfell-3 fault block. During the second quarter of 2025, the partnership drilled the Winterfell-4 well to test a separate fault block and define the eastern extent of the Winterfell reservoir area. The Winterfell-4 well was abandoned in September 2025 by the operator due to challenges during completion operations arising from the collapse of the production casing. The partnership will continue to review alternative options to access those resources with near-term activity in 2026 focused on restoring production from the Winterfell-3 fault block.
Current report
In February 2026, Kosmos entered into a strategic alliance with Shell, exchanging interests in five exploration blocks in the Norphlet trend. Shell and Kosmos now have alignment over ten blocks in the Gulf of America to explore multiple prospects, including Trailblazer. Drilling of Trailblazer is planned for 2027 with Kosmos designated as development operator.
Current report
On February 24, 2026, we entered into a Share Sale and Purchase Agreement with a subsidiary of Panoro Energy ASA for the sale of all of our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea for upfront cash consideration of $180 million, subject to certain adjustments, and future contingent consideration of up to $39.5 million, comprising $12.5 million linked to production performance at the Ceiba field and $9 million payable in each of 2027, 2028 and 2029, which are subject to certain oil price and production thresholds. The transaction has received approval from the Government of Equatorial Guinea and completion only remains subject to CEMAC customary approval. While we expect to close the transaction around the middle of 2026, there can be no assurances that closing will ultimately occur or that it may not be delayed. As such, the Company has elected to report on the business throughout this Form 10-K on the basis that the transaction has not yet closed and that the Company continues to own all of the participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. All such references to the Company’s future plans and expectations for the Equatorial Guinea business unit should therefore be read in light of the ongoing transaction.
Current report
In February 2026, we notified our partners that we are withdrawing from Block EG-01.
Current report
On Yakaar-Teranga, we are working with PETROSEN to withdraw from the block given we have not been able to attract a suitable partner and agree a commercially attractive development concept with the government of Senegal. Accordingly, during the year ended December 31, 2025, we wrote off $143.7 million of unproved property costs associated with the Yakaar and Teranga discoveries, which were largely incurred before 2020.
Current report
Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $100.0 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of the ramp-up of LNG production resulting in first LNG and condensate sales in 2025 at the GTA Phase 1 project in Mauritania and Senegal and higher depletion rates per Boe across our portfolio partially offset by lower sales volumes at Jubilee and Equatorial Guinea.
Current report
Leverage was elevated in 2025 given lower oil prices and the impact of operating costs during ramp-up of the GTA Phase 1 project combined with lower Company production. As a result, in July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment made this covenant less restrictive for the two scheduled financial covenant assessment dates in September 2025 and March 2026, up to a maximum of 4.0x and 4.25x respectively, and returned to the originally agreed upon ratio of 3.50x for assessment dates thereafter. In February 2026, we further amended the debt cover ratio calculation through September 2026. This most recent amendment makes the covenant less restrictive for the two scheduled financial covenant assessment dates in March 2026 and September 2026, up to a maximum of 4.5x and 4.25x respectively, and for purposes of the financial covenant assessment date in March 2026, the calculation will be made excluding the Company’s Mauritania and Senegal business unit. The debt cover ratio returns to the originally agreed upon ratio of 3.5x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower potential oil prices and the impact of operating costs during ramp-up of the GTA Phase 1 project on our results of operations.
Current report
(1)As of December 31, 2025, the undrawn availability under the GoA Term Loan Facility was $100 million, subject to certain conditions on borrowing. In January 2026, we received net proceeds of $98.5 million from funding the second tranche after deducting fees and other expenses. The net proceeds were used, together with cash on hand, to fund the redemption of the remaining $100.0 million of the 7.125% Senior Notes due 2026.
Current report
(2)As of December 31, 2025, the undrawn availability under the Facility was $150.0 million, subject to certain conditions on borrowing. In January 2026, the Company issued $350 million of 11.250% Senior Secured Bonds due in 2031 in the Nordic market. In February 2026, Kosmos used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of the 7.750% Senior Notes due 2027 and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.
Current report
•advance development efforts in the Gulf of America and in Mauritania and Senegal; and
Current report
•execute facilities integrity activities in Equatorial Guinea.
Current report
•Approximately $15 million related to facilities integrity activities in Equatorial Guinea.
Current report
In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion. As of December 31, 2025, borrowings under the Facility totaled $1.2 billion and the undrawn availability under the facility was $150.0 million. In February 2026, the Company used a portion of the net proceeds from the Nordic bond offering to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.
Current report
3.125% Convertible Senior Notes due 2030
Current report
GoA Term Loan Facility
Current report
On September 24, 2025, the Company entered into a senior secured term loan credit agreement secured by first priority liens on all the Company’s Gulf of America assets (as defined in the GoA Term Loan credit agreement). The GoA Term Loan Facility is a four-year term loan structured in two tranches, with the first tranche an aggregate principal amount of $150.0 million, which was funded in October 2025, and a second tranche of an additional $100.0 million, which was funded in January 2026. The net proceeds were used, together with cash on hand, to fund the redemption of the $250.0 million in aggregate, of the 7.125% Senior Notes due 2026.
Current report
Interest on outstanding loans under the GoA Term Loan Facility is payable quarterly in arrears at a rate per annum equal to 3.75% plus the term SOFR reference rate administered by CME Group Benchmark Administration Limited for the relevant period published. The GoA Term Loan Facility is now fully drawn and matures in 2029, with principal payments beginning June 30, 2026.
Current report
The GoA Term Loan Facility contains customary affirmative and negative covenants, including covenants that affect our ability to incur additional indebtedness, create liens, merge, dispose of assets, and make distributions, dividends, investments or capital expenditures, among other things. The GoA Term Loan Facility requires the Company to maintain certain financial covenants including:
Current report
•the GoA field life coverage ratio (as defined in the glossary), not less than 1.50x; and
Current report
•the GoA net leverage ratio (as defined in the glossary), not more than 3.50x
Current report
The GoA Term Loan Facility includes certain representations and warranties, indemnities and events of default that, subject to materiality thresholds and grace periods, arise as a result of a payment of default, failure to comply with covenants, material inaccuracy of representation or warranty, and certain bankruptcy or insolvency proceedings. If there is an event of default, all or any portion of the outstanding indebtedness may be immediately due and payable and other rights may be exercised including against the collateral.
Current report
GTA Nordic Bonds
Current report
In January 2026, we issued one series of senior secured GTA Nordic bonds totaling $350.0 million. Our 11.250% senior secured GTA Nordic bonds mature in January 2031, unless earlier redeemed or repurchased. Interest is payable semi-annually in arrears each July 29 and January 29, commencing July 29, 2026.
Current report
The GTA Nordic bonds were issued by Kosmos Energy GTA Holdings, a wholly-owned subsidiary of Kosmos Energy Ltd., and are fully and unconditionally guaranteed by the Company, as well as the Company’s wholly-owned subsidiaries, Kosmos Energy Tortue Finance, Kosmos Energy Senegal, Kosmos Energy Investments Senegal Limited and Kosmos Energy Mauritania. The GTA Nordic bonds are also guaranteed on an unsecured basis by certain of the Company’s subsidiaries that also guarantee the Company’s existing senior unsecured notes.
Current report
(5)In January 2026, we used net proceeds of $98.5 million from the funding of the second tranche of the GoA Term Loan Facility, together with cash on hand, to fund the redemption of the remaining $100.0 million of the 7.125% Senior Notes due 2026.
Current report
(6)In January 2026, the Company issued $350.0 million of 11.250% Senior Secured Bonds due 2031 in the Nordic market. In February 2026, Kosmos used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of the 7.750% Senior Notes due 2027 and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.
Current report
Once the Tortue Phase 1 SPA Commercial Operations Date was achieved in February 2026, we have a commitment to our buyer under the Tortue Phase 1 SPA, BP Gas Marketing Limited, to deliver our proportionate share of a minimum annual contract quantity of LNG of 127,951,000 MMBtu, which is equivalent to approximately 2.45 million tonnes per annum, subject to certain downward adjustments by the sellers. Under certain circumstances, in the event the annual quantities provided are lower than the minimum annual contract quantity, Kosmos may be obligated to credit or pay a portion of the Contract Price to BP Gas Marketing Limited for the shortfall volumes.
Current report
In February 2026, the TEN partnership executed the final Sale and Purchase Agreement to acquire the TEN FPSO from MODEC, Inc. at the end of its current lease in 2027 for a gross purchase price of $205.0 million. We have a commitment to Tullow for our proportionate share of the gross purchase price.
Removed paragraphs (37)
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
In October 2024, pursuant to a voluntary cancellation notice sent by the Company, the Corporate Revolver was terminated.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
BirAllah and Orca Discoveries
Previous report
In April 2024, the petroleum contract covering the BirAllah and Orca discoveries offshore Mauritania expired.
Previous report
(1)Includes activity related to the pre-emption transaction with Tullow on March 13, 2022.
Previous report
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.
Previous report
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.
Previous report
•completion of the first phase of GTA development; and
Previous report
•advancing appraisal and development efforts for existing discoveries in the Gulf of America and internationally.
Previous report
•Approximately $50 million related to the completion of the first phase of the Greater Tortue Ahmeyim development in Mauritania and Senegal;
Previous report
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.
Previous report
Corporate Revolver
Previous report
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.
Previous report
3.125% Convertible Senior Notes due 20230
Previous report
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:
Previous report
•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;
Previous report
•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;
Previous report
•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
Previous report
•upon the occurrence of certain specified corporate events.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Previous report
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.
Reworded paragraphs (30)
Previous wording
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.
Current wording
Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world’s growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success.
Previous wording
During the year ended December 31, 2024, Ghana production averaged approximately 120,900 Boepd gross (41,300 Boepd net).
Current wording
During the year ended December 31, 2025, Ghana production averaged approximately 93,100 Boepd gross (31,100 Boepd net).
Previous wording
During the year ended December 31, 2024, Gulf of America production averaged approximately 15,300 Boepd (net) (~83% oil).
Current wording
During the year ended December 31, 2025, Gulf of America production averaged approximately 17,600 Boepd (net) (~84% oil).
Previous wording
Production in Equatorial Guinea averaged approximately 25,000 Bopd gross (8,700 Bopd net) for the year ended December 31, 2024.
Current wording
Production in Equatorial Guinea averaged approximately 20,400 Bopd gross (7,200 Bopd net) for the year ended December 31, 2025, impacted by multiple flow pump (MPP) mechanical failures at Ceiba during the second quarter of 2025. One pump is currently back online with another pump expected to be online in the first quarter of 2026.
Previous wording
In December 2024, we submitted a formal notice to the Ministry of Hydrocarbons and Mining Development that we are electing to exit Block 21.
Current wording
In October 2025, we submitted a formal notice to the Ministry of Hydrocarbons and Mining Development that we are electing to exit Block S offshore Equatorial Guinea.
Previous wording
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.
Current wording
Production in Mauritania and Senegal averaged approximately 35,000 Boepd gross (8,500 Boepd net) for the full year ended December 31, 2025, as production from the Greater Tortue Ahmeyim (GTA) liquefied natural gas (LNG) project ramped up. The GTA LNG project achieved first gas production from the subsea system to the FPSO on December 31, 2024. First LNG was achieved in February 2025 and the first gross LNG cargo was successfully exported in April 2025. Eighteen and a half gross LNG cargos and one condensate cargo were lifted in 2025. The Gimi FLNG vessel Commercial Operations Date was achieved in the second quarter of 2025 with successful ramp-up to the daily contracted sales volume level under the Tortue Phase 1 SPA, equivalent to approximately 2.45 million tonnes per annum. Production averaged approximately 58,200 Boepd gross (14,200 Boepd net) for the three months ended December 31, 2025. Additionally, the Gimi FLNG vessel operated at nameplate capacity in December 2025, reaching a peak production rate of approximately 3.0 million tonnes per annum.
Previous wording
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.
Current wording
All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal, the Gulf of America. Certain operating results and statistics for the years ended December 31, 2025, 2024 and 2023 are included in the following tables. For a discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, please refer to Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024.
Previous wording
(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.
Current wording
(1)Substantially all NGLs and natural gas sales in Ghana and the Gulf of America are associated production from our oil wells and, therefore, production costs metrics are presented under a common unit of measure. In Mauritania and Senegal, all condensate sales and LNG sales are associated production from our gas wells. Includes $93.4 million of pre-production operating costs for the year ended December 31, 2024 incurred before production commenced at the Greater Tortue Ahmeyim Phase 1 project in Mauritania and Senegal. Oil and gas production costs related to the LNG production at the GTA Phase 1 project were $237.6 million for the year ended December 31, 2025. First LNG was achieved in February 2025 and the first LNG cargo was successfully completed in April 2025. Production costs per Bcf in Mauritania and Senegal was $14.68 for the year ended December 31, 2025. Mauritania and Senegal LNG sales are presented as gas sales in the table.
Previous wording
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.
Current wording
Oil and gas revenue. Oil and gas revenue decreased by $387.0 million during the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily as a result of lower average realized oil and gas prices and lower production resulting in lower sales volume at Jubilee and Equatorial Guinea partially offset by increased sales volumes in Mauritania and Senegal with LNG and condensate cargo sales beginning in 2025. We sold 22,414 MBoe at an average realized price per barrel of oil equivalent of $57.48 in 2025 and 23,507 MBoe at an average realized price per barrel of oil equivalent of $71.27 in 2024.
Previous wording
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.
Current wording
Oil and gas production. Oil and gas production costs increased by $178.4 million during the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily as a result of a full year of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal.
Previous wording
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.
Current wording
Exploration expenses. Exploration expenses increased by $103.7 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of approximately $58.5 million of exploration expense related to the Winterfell-4 step out well which was plugged and abandoned during the third quarter of 2025 and approximately $143.7 million of previously capitalized costs related to the Yakaar and Teranga discoveries incurred under the Cayar Offshore Profound Block license that were written off to exploration expense for the year ended December 31, 2025 compared to approximately $28.0 million related to the S-6 “Akeng Deep” ILX prospect in Block S offshore Equatorial Guinea which encountered sub-commercial quantities of hydrocarbons and was plugged and abandoned in the fourth quarter of 2024 and approximately $37.2 million of previously capitalized costs related to the Asam discovery in Block S offshore Equatorial Guinea that were written off to exploration expense for the year ended December 31, 2024, partially offset by decreased seismic, geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.
Previous wording
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.
Current wording
Impairment of long-lived assets. As a result of negative proved oil and gas reserves revisions in certain of our Gulf of America fields, primarily Winterfell, we recorded a proved property impairment charge of $177.6 million during the year ended December 31, 2025.
Previous wording
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 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.
Current wording
Interest and other financing costs, net. Interest and other financing costs, net increased by $134.8 million during the year ended December 31, 2025, as compared to the year ended December 31, 2024 primarily as a result of decreased capitalized interest for the year ended December 31, 2025 related to the GTA Phase 1 project post first gas production in December 2024 partially offset by a $25.2 million loss on debt modifications and extinguishments primarily related to the amendment and restatement of the Facility during the second quarter of 2024.
Previous wording
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.
Current wording
Income tax expense (benefit). For the years ended December 31, 2025 and 2024, our overall effective tax rates were impacted by the difference in our 21% U.S. income tax reporting rate and the 35% statutory tax rate applicable to our Ghanaian operations and the 25% statutory tax rate applicable to our Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate, or jurisdictions where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in the U.S.
Previous wording
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.
Current wording
As such, our 2026 capital budget is based on our exploitation plans for our producing assets in Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America, and our development activities in the Gulf of America and in Mauritania and Senegal.
Previous wording
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.
Current wording
Our future financial condition and liquidity can be impacted by, among other factors, the success of our exploitation, exploration and appraisal drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil, natural gas, and LNG and our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
Previous wording
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.
Current wording
As of December 31, 2025, borrowings under the Facility totaled approximately $1.2 billion and the undrawn availability under the facility was $150.0 million. In September 2025, during the Fall 2025 redetermination, the Company’s lending syndicate approved a borrowing base at the full Facility size of $1.35 billion.
Previous wording
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.
Current wording
Net cash provided by operating activities. Net cash provided by operating activities in 2025 was $134.0 million compared with net cash provided by operating activities of $678.2 million in 2024 and $765.2 million in 2023, respectively. The decrease in cash provided by operating activities in the year ended December 31, 2025 when compared to the same period in 2024 is primarily a result of lower average realized oil and gas prices, lower sales volumes in Ghana and Equatorial Guinea, higher oil and gas production costs related to the ramp-up of LNG production at the GTA Phase 1, partially offset by increased sales volumes in Mauritania and Senegal with LNG and condensate cargo sales beginning in 2025 and lower workover expense in Equatorial Guinea. The decrease in cash provided by operating activities in the year ended December 31, 2024 when compared to the same period in 2023 is primarily a result of increased oil and gas production costs for the year ended December 31, 2024 as a result of pre-production operating costs associated with the GTA Phase 1 project, planned workovers in the Gulf of America business unit, and increased production costs in Equatorial Guinea, together with lower average realized oil prices, offset by changes in working capital.
Previous wording
(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.
Current wording
(3)When our debt cover ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. As of December 31, 2024, our debt cover ratio was 2.54x. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance through 2025. As of December 31, 2025, our debt cover ratio was 5.49x. Our next financial covenant assessment date is March 31, 2026, after which date we will be required to restrict approximately $50.0 million in cash as required under the terms of the Facility unless otherwise waived by the lenders
Previous wording
•drill additional infill wells and execute exploitation and production activities in Ghana, Equatorial Guinea and the Gulf of America;
Current wording
•drill additional infill wells in Ghana and the Gulf of America;
Previous wording
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.
Current wording
We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our paying interests in our operations including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third‑party projects, the availability of suitable equipment and qualified personnel and our cash flows from operations. We also evaluate potential corporate and asset acquisition and divestment opportunities, which may impact our budget assumptions. These assumptions are inherently subject to significant business, political, economic, regulatory, health, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate; or one or more of our assumptions proves to be incorrect, or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell assets, equity or debt securities or obtain additional bank credit facilities. The sale of equity securities could 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.
Previous wording
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:
Current wording
We estimate we will spend approximately $350 million of capital for the year ending December 31, 2026, excluding any acquisitions or divestiture of oil and gas properties during the year. This capital expenditure budget consists of:
Previous wording
•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;
Current wording
•Approximately $275 million related to maintenance activities across our Ghana and Gulf of America assets, including infill development drilling and TEN FPSO purchase payments;
Previous wording
•Less than $75 million related to progressing our appraisal and development programs in the Gulf of America, Mauritania and Senegal.
Current wording
•Approximately $60 million related to progressing our development programs in the Gulf of America and in Mauritania and Senegal; and
Previous wording
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.
Current wording
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. We were in compliance with the financial covenants contained in the Facility, as amended, as of September 30, 2025 (the most recent assessment date). The Facility contains customary cross default provisions.
Previous wording
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.
Current wording
We have three series of senior notes outstanding, which we collectively refer to as the “Senior Notes.” Our 7.750% Senior Notes have an outstanding balance of $350.0 million as of December 31, 2025 and mature on May 1, 2027. In February 2026, we used a portion of the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $182.5 million of the 7.750% Senior Notes. Interest is payable on the 7.750% Senior Notes each May 1 and November 1. Our 7.500% Senior Notes have an outstanding balance of approximately $400.3 million on December 31, 2025 and mature on March 1, 2028. Interest is payable on the 7.500% Senior Notes each March 1 and September 1. Our 8.750% Senior Notes have an outstanding balance of $500.0 million on December 31, 2025 and mature on October 1, 2031. Interest is payable on the 8.750% Senior Notes each April 1 and October 1.
Previous wording
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.
Current wording
The 3.125% Convertible Senior Notes indenture contains customary terms and covenants.
Previous wording
(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.
Current wording
(4)In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total remaining commitment to be approximately $122.6 million as of December 31, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated fifteen year period based on the expiration date of the WCTP and DT Petroleum Agreements, which has now been extended to 2040. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.
Previous wording
As of December 31, 2024, we have a commitment to drill one development well in Equatorial Guinea.
Current wording
As of December 31, 2025, we have a commitment to drill one development well in Equatorial Guinea. As part of the license extensions of WCTP and DT Petroleum Agreements in Ghana, we have a commitment to drill a minimum of ten development wells under the amended Jubilee plan of development.
Previous wording
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.
Current wording
Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a derivative that is separated from the host contract for accounting purposes. The host contract is the receivable from sales at the spot price on the date of sale. The derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
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.