Kosmos Energy Ltd.
For the period ended Mar 31, 2026. Filed May 5, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2026 · Filed May 5, 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-Q
Period ended 2025-09-30; filed 2025-11-04.
0001509991-25-000072
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-03-31; filed 2026-05-05.
0001509991-26-000027
Item 2. 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 139 previous paragraphs and 137 current paragraphs.
76 unchanged; 31 reworded; 30 added; 29 removed; 3 previous and 0 current paragraphs rearranged.
Tables are not compared: 7 previous and 6 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 (30)
Current report
On January 12, 2026, we received net proceeds of $98.5 million from the funding of the second tranche of the GoA Term Loan after deducting fees and expenses. On January 13, 2026, the net proceeds were used, together with cash on hand, to complete the redemption of the remaining outstanding balance of $100.0 million of the 7.125% Senior Notes due 2026. On March 24, 2026, we made a voluntary prepayment of $53.6 million against the GoA Term Loan. On May 1, 2026, the GoA Term Loan Facility was amended to apply this prepayment in full satisfaction of the scheduled principal amount due on the first scheduled amortization payment date on June 30, 2026, and then ratably to all remaining scheduled principal payments of the outstanding loans. The amendment also deferred all future scheduled amortization payment dates in 2026, 2027 and 2028 such that they will now be due on October 1, January 1, April 1 and July 1 in each of 2026, 2027 and 2028. As a result of the amendment, there is only one remaining scheduled amortization payment in 2026 to be paid on October 1, 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”). In the first quarter of 2026, the Company used the net proceeds from the Nordic bond offering to fund the repurchase of an aggregate principal amount of $249.8 million of the 7.750% Senior Notes due 2027 pursuant to the Company’s cash tender offer announced on January 12, 2026 and open market repurchases, and to make a voluntary early principal repayment of $100.0 million on outstanding borrowings under the Facility.
Current report
On March 10, 2026, the Company launched and priced a registered underwritten public offering of 112.1 million shares of common stock, resulting in net proceeds to Kosmos of approximately $206.4 million. The offering closed on March 12, 2026.
Current report
In December 2025, the Jubilee and TEN partnerships received approval from the Government of Ghana to extend to 2040 the WCTP and the DT licenses, which cover the Jubilee and TEN fields offshore Ghana. Additionally, 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 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, Tullow Oil plc, as Operator of the TEN partnership, executed the final Sale and Purchase Agreement enabling the partnership 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
At Winterfell, the partnership spud Winterfell-5 in April 2026. Winterfell-5 is designed as a twin well to Winterfell-3 and is expected to restore production from the Winterfell-3 fault block. Winterfell-5 is expected online in the third quarter of 2026. In April 2026, Winterfell-2 was shut-in pending a future intervention.
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 covering ten blocks in the Gulf of America to explore multiple prospects, including Trailblazer. Drilling of the Trailblazer exploration well is planned for the first half of 2027, with Kosmos designated as development operator.
Current report
Production in Equatorial Guinea averaged approximately 16,000 Bopd gross (5,600 Bopd net) in the first quarter of 2026, with remediation work on the failed subsea multiphase flow pump (MPP) at Ceiba progressing.
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 our 40.4% participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea for upfront cash consideration of $180.0 million, subject to certain adjustments and future contingent consideration of up to $39.5 million, comprised of $12.5 million linked to future production performance at the Ceiba field and $9.0 million payable in each of the years 2027, 2028 and 2029, subject to certain production and oil price thresholds. The transaction has an effective date of January 1, 2025, 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. Operating results throughout this Form 10-Q continue to include the operating results of the EG business on the basis that the transaction has not yet closed and that the Company continues to own all of the participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. All such references to the Company’s future plans and expectations for the Equatorial Guinea business unit should therefore be read in light of the ongoing transaction.
Current report
In the first quarter of 2026, we withdrew from Block EG-01 offshore Equatorial Guinea.
Current report
Greater Tortue Ahmeyim (GTA) Field
Current report
Production in Mauritania and Senegal from GTA averaged approximately 69,800 Boepd gross (17,000 Boepd net) in the first quarter of 2026, approximately 2.85 million tonnes per annum, or 5% above FLNG nameplate capacity.
Current report
Block 5 offshore Sao Tome and Principe is scheduled to expire during the second quarter of 2026 and, accordingly, we wrote off related leasehold costs.
Current report
(1)Substantially all NGLs and natural gas sales in Ghana and the Gulf of America are associated production from our oil wells and, therefore, production costs metrics are presented under a common unit of measure. In Mauritania and Senegal, all condensate sales and LNG sales are associated production from our gas wells and the first LNG cargo was successfully completed in April 2025. Oil and gas production costs related to LNG production at the GTA Phase 1 project were $55.3 million and $58.1 million for the three months ended March 31, 2026 and March 31, 2025, respectively. Production costs per Mcfe in Mauritania and Senegal was $6.80 for the three months ended March 31, 2026. Mauritania and Senegal LNG sales are presented as gas sales in the table.
Current report
(2)Includes results of the EG business on the basis that the transaction has not yet closed and that the Company continues to own all of the participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea. See Note 3 - Acquisitions and Divestitures for additional information.
Current report
Oil and gas production. Oil and gas production costs decreased by $36.7 million during the three months ended March 31, 2026 as compared to the three months ended March 31, 2025 primarily as a result of lower routine operating costs across all of our business units and decreased workover expense in our Gulf of America business unit.
Current report
(1) When our debt cover ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.750% Senior Notes, the 7.500% Senior Notes, the 8.750% Senior Notes and the 3.125% Convertible Senior Notes or the Facility, whichever is greater. During the first quarter of 2025, the Facility lenders waived the requirement to maintain a restricted cash balance until the March 31, 2026 financial covenant test date. Our debt cover ratio for the most recent March 31, 2026 financial covenant test date exceeded 2.50x and the estimated restricted cash funding requirement is approximately $47.0 million. We are currently in discussions with the Facility lenders seeking approval to extend the prior waiver, but if no approval is granted then we plan to start funding the debt service reserve account in the second quarter, as required under the terms of the Facility.
Current report
(2) Excludes $80.1 million TEN FPSO finance lease liability. For purposes of the debt cover ratio calculation under the Facility, the finance lease liability is included in net debt.
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 April 2026 during the Spring 2026 redetermination, the Company’s lending syndicate approved a borrowing base at approximately $1.25 billion. Following closing of the sale of all our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea, the Company’s production assets in Equatorial Guinea will no longer be included in the borrowing base amount, and we have agreed with the lending syndicate to further reduce the borrowing base to approximately $1.2 billion.
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
The Bond Terms governing the GTA Nordic bonds also require Kosmos Energy GTA Holdings to maintain certain financial covenants including:
Current report
•Minimum Liquidity (as defined in the Bond Terms) of not less than $17.5 million or 5% of the outstanding GTA Nordic bonds, whichever is greater; and
Current report
•an Asset Coverage Ratio (as defined in the Bond Terms) of at least 1.25x.
Current report
Equity Issuance
Current report
On March 10, 2026, the Company launched and priced a registered underwritten public offering of 112.1 million shares of common stock, resulting in net proceeds to Kosmos of approximately $206.4 million. The offering closed on March 12, 2026.
Removed paragraphs (29)
Previous 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 partnership has prepared amendments to the respective Petroleum Agreements, a Jubilee Plan of Development Amendment, an amendment to the Jubilee Gas Sales Agreement covering future gas sales from the Jubilee Field, as well as the other necessary documents for submission to the Government of Ghana for parliamentary approval.
Previous report
In July 2024, we announced start-up of oil production from the first phase of the Winterfell development in the Green Canyon area of the Gulf of America (25% working interest). In October 2024, shortly after startup of the third well, production at the field was curtailed due to sand production from the third well. 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 evaluates 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 Wintefell-4 well was abandoned in September 2025 by the operator due to challenges during completion operations arising from the collapse of the production casing. As a result, all associated drilling and completion capitalized costs of approximately $51.1 million related to
Previous report
Winterfell-4 have been written off in the third quarter of 2025. 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.
Previous report
Production in Equatorial Guinea averaged approximately 17,700 Bopd gross (6,200 Bopd net) in the third quarter of 2025, impacted by multiple subsea multiphase flow pump (MPP) mechanical failures at Ceiba during the second quarter of 2025. The first pump was repaired ahead of schedule early in the fourth quarter of 2025, and the second pump is now also expected online in the fourth quarter followed by the third pump in the first quarter of 2026.
Previous report
In October 2025, we received approval from the Ministry of Hydrocarbons and Mining Development for a twelve month extension to December 2026 for the current exploration phase of Block EG-24.
Previous report
Greater Tortue Ahmeyim Project
Previous report
Production in Mauritania and Senegal averaged approximately 46,900 Boepd gross (11,400 Boepd net) in the third quarter of 2025, as production from the GTA field continued to ramp up.
Previous report
The Greater Tortue Ahmeyim (GTA) liquified natural gas (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 with 13.5 gross cargoes lifted through October 2025, along with the first gross condensate cargo. Additionally, 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.
Previous report
In May 2025, we received approval for a twelve month extension to May 2026 for the current exploration phase for Block 5 offshore Sao Tome and Principe.
Previous 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 nine months ended September 30, 2025. Based on our evaluation, we have determined that the impact of OBBBA is not material to the Company’s financial position or results.
Previous report
(1)Includes $59.4 million and $186.6 million for the three and nine months ended September 30, 2025, respectively, related to the LNG production at the GTA Phase 1 project in Mauritania and Senegal. All gas sales in Mauritania and Senegal are LNG sales. First LNG was achieved in February 2025 and the first LNG cargo was successfully completed in April 2025.
Previous report
(2)Includes $39.7 million and $57.9 million for the three and nine months ended September 30, 2024, respectively, of oil and gas production costs related to the LNG production at the GTA Phase 1 project in Mauritania and Senegal.
Previous report
Oil and gas production. Oil and gas production costs increased by $14.2 million during the three months ended September 30, 2025 as compared to the three months ended September 30, 2024 primarily as a result of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal offset by lower operating costs at Jubilee and Ceiba.
Previous report
Depletion, depreciation and amortization. Depletion, depreciation and amortization increased by $20.8 million during the three months ended September 30, 2025, as compared with the three months ended September 30, 2024 primarily as a result higher depletion rates per boe across our portfolio owing to increased cost basis related to the respective development activities in 2024 partially offset by lower sales volumes across our portfolio.
Previous report
Nine months ended September 30, 2025 compared to nine months ended September 30, 2024
Previous report
Oil and gas revenue. Oil and gas revenue decreased by $284.1 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of lower average realized oil and gas prices and lower production and sales volume at Jubilee and Ceiba offset by increased sales volumes in Mauritania & Senegal with first LNG cargo sales beginning in 2025. We sold 16,624 MBoe at an average realized price per barrel equivalent of $59.78 during the nine months ended September 30, 2025 and 17,465 MBoe at an average realized price per barrel equivalent of $73.16 during the nine months ended September 30, 2024.
Previous report
Oil and gas production. Oil and gas production costs increased by $180.3 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of operating costs associated with the ramp-up of LNG production at the GTA Phase 1 project in Mauritania and Senegal offset by lower average oil and gas operating costs at Jubilee and Ceiba.
Previous report
Exploration expenses. Exploration expenses increased by $28.7 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of approximately $51.1 million of exploration expense for the nine months ended September 30, 2025 related to the Winterfell-4 step out well which was plugged and abandoned during the third quarter of 2025 offset by decreased geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.
Previous report
General and administrative expenses. General and administrative expenses decreased during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024 primarily as a result of a reduction in employee compensation during 2025.
Previous report
Interest and other financing costs, net. Interest and other financing costs, net increased $88.8 million during the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024, primarily as a result of decreased capitalized interest related to the GTA Phase 1 project post first gas production in December 2024 partially offset by a $24.8 million loss on debt modifications and extinguishments related to the amendment and restatement of the Facility during the second quarter of 2024.
Previous report
Income tax expense. For the nine months ended September 30, 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 and 25% statutory tax rate applicable to our 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.
Previous report
(1)As of September 30, 2025, the undrawn availability under the GoA Term Loan Facility was $250 million, subject to certain conditions on borrowing. On October 1, 2025, we received net proceeds of $147.2 million after deducting fees and other expenses. On October 6, 2025, the net proceeds were used, together with cash on hand, to fund the redemption of a portion of the 7.125% Senior Notes due 2026 totaling $150.0 million in aggregate, thereby decreasing the remaining availability under the GoA Term Loan Facility to $100 million. The proceeds from any additional borrowings on the GoA Term Loan Facility is expected to be used to fund the redemption or repayment of the remainder of the 7.125% Senior Notes due 2026.
Previous report
• complete development of the first phase of GTA; and
Previous report
• advance appraisal and development efforts for the existing discoveries in the Gulf of America and internationally.
Previous report
•Approximately $75 million related to the completion of the first phase of the GTA development in Mauritania and Senegal;
Previous 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:
Previous report
•the GoA field life coverage ratio (as defined in the glossary), not less than 1.50x; and
Previous report
•the GoA net leverage ratio (as defined in the glossary), not more than 3.50x.
Previous 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.
Reworded paragraphs (31)
Previous wording
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.
Current wording
In April 2026, during the Spring 2026 redetermination, the Company’s lending syndicate approved a borrowing base at approximately $1.25 billion for the Facility, and a further reduction to approximately $1.2 billion upon the close of the sale of all our participating interest in the Ceiba Field and Okume Complex production assets located in Block G offshore Equatorial Guinea.
Previous wording
During the third quarter of 2025, Ghana production averaged approximately 93,600 Boepd gross (31,300 Boepd net).
Current wording
During the first quarter of 2026, Ghana production averaged approximately 103,300 Boepd gross (35,400 Boepd net).
Previous wording
Jubilee development drilling progressed in the third quarter of 2025 bringing one producer well successfully online in July 2025. After undergoing scheduled maintenance, the rig is back in the field and currently drilling an additional producer well in the Jubilee Field in the fourth quarter of 2025 to be followed by drilling four planned producer wells and an additional water injector well in 2026.
Current wording
Jubilee development drilling progressed in the first quarter of 2026 bringing two producer wells successfully online during the first quarter of 2026. The remaining development drilling campaign in 2026 is planned to include three additional producer wells and one additional water injector well.
Previous wording
Production from the Gulf of America averaged approximately 16,600 Boepd net (~84% oil) for the third quarter of 2025.
Current wording
Production from the Gulf of America averaged approximately 16,800 Boepd net (~84% oil) for the first quarter of 2026.
Previous wording
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. Final investment decision and a farm down to reduce Kosmos’ working interest is expected in 2026.
Current wording
On Tiberius, Kosmos (operator, 50% working interest) continues to progress the development 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. We achieved a final investment decision in March 2026 with first oil targeted in the second half of 2028. We are also working on a potential farm down to reduce Kosmos’ working interest to approximately 33%, which is expected around the middle of 2026.
Previous wording
All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Certain operating results and statistics for the three and nine months ended September 30, 2025 and 2024 are included in the following tables:
Current wording
All of our results, as presented in the table below, represent operations from Ghana, Equatorial Guinea, Mauritania, Senegal and the Gulf of America. Certain operating results and statistics for the three months ended March 31, 2026 and 2025 are included in the following tables:
Previous wording
Oil and gas revenue. Oil and gas revenue decreased by $96.8 million during the three months ended September 30, 2025 as compared to the three months ended September 30, 2024 primarily as a result of lower average realized oil and gas prices and lower production and sales volumes at Jubilee and Ceiba offset by an increase in production and sales volumes in Mauritania & Senegal with first LNG cargo sales beginning in 2025. We sold 5,515 MBoe at an average realized price per barrel equivalent of $56.39 during the three months ended September 30, 2025 and 5,811 MBoe at an average realized price per barrel equivalent of $70.18 during the three months ended September 30, 2024.
Current wording
Oil and gas revenue. Oil and gas revenue increased by $80.6 million during the three months ended March 31, 2026 as compared to the three months ended March 31, 2025 primarily as a result of higher production and sales volumes at Jubilee and GTA, with GTA producing at 5% above FLNG nameplate capacity offset by lower average realized oil and gas prices. We sold 6,643 MBoe at an average realized price per barrel equivalent of $55.81 during the three months ended March 31, 2026 and 4,445 MBoe at an average realized price per barrel equivalent of $65.27 during the three months ended March 31, 2025.
Previous wording
Exploration expenses. Exploration expenses increased by $40.3 million during the three months ended September 30, 2025, as compared to the three months ended September 30, 2024 primarily as a result of approximately $51.1 million of exploration expense for the three months ended September 30, 2025 related to the Winterfell-4 step out well which was plugged and abandoned during the third quarter of 2025 offset by decreased geological and geophysical studies and related costs as part of the Company’s focus on managing costs across our portfolio.
Current wording
Exploration expenses. Exploration expenses increased by $10.1 million during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025 primarily as a result of the write-off of exploration leasehold costs during the first quarter of 2026, partially offset by decreased seismic, geological and geophysical studies and related costs in the first quarter of 2026 as part of the Company’s focus on managing costs across our portfolio.
Previous wording
General and administrative expenses. General and administrative expenses decreased during the three months ended September 30, 2025, as compared to the three months ended September 30, 2024 primarily as a result of a reduction in employee compensation during 2025.
Current wording
General and administrative expenses. General and administrative expenses increased $1.5 million during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025 primarily as a result of lower technical rate fees in the first quarter of 2026, partially offset by lower gross general and administrative costs.
Previous wording
Depletion, depreciation and amortization. Depletion, depreciation and amortization increased $101.7 million during the nine months ended September 30, 2025, as compared with the nine months ended September 30, 2024 primarily as a result of higher depletion rates per boe across our portfolio.
Current wording
Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased by $0.8 million during the three months ended March 31, 2026, as compared with the three months ended March 31, 2025 primarily as a result lower depletion rates per boe across our portfolio offset by higher sales volumes at Jubilee and GTA.
Previous wording
Interest and other financing costs, net. Interest and other financing costs, net increased by $35.8 million during the three months ended September 30, 2025, as compared to the three months ended September 30, 2024 primarily as a result of decreased capitalized interest related to the GTA Phase 1 project post first gas production in December 2024.
Current wording
Interest and other financing costs, net. Interest and other financing costs, net increased by $7.0 million during the three months ended March 31, 2026, as compared to the three months ended March 31, 2025 primarily as a result of increased debt and lower capitalized interest as a result of the Yakaar and Teranga write-off in December 2025.
Previous wording
Derivatives, net. During the three months ended September 30, 2025 and 2024, we recorded a gain of $3.6 million and a gain of $15.3 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.
Current wording
Derivatives, net. During the three months ended March 31, 2026 and 2025, we recorded a loss of $252.0 million and a loss of $6.7 million, respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods.
Previous wording
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 support our remaining capital program for 2025.
Current wording
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 remaining capital program for 2026.
Previous wording
As such, our 2025 capital budget is based on our exploitation and production plans for 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 exploration, appraisal and exploitation 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 exploration, appraisal, exploitation 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 exploration, appraisal and exploitation 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 exploration, appraisal, exploitation and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
Previous wording
The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the nine months ended September 30, 2025 and 2024:
Current wording
The following table presents the sources and uses of our cash and cash equivalents and restricted cash for the three months ended March 31, 2026 and 2025:
Previous wording
Net cash provided by operating activities. Net cash provided by operating activities for the nine months ended September 30, 2025 was $98.7 million compared with net cash provided by operating activities for the nine months ended September 30, 2024 of $502.5 million. The decrease in cash provided by operating activities in the nine months ended September 30, 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 partially offset by increased sales volumes in Mauritania & Senegal with first LNG cargo sales beginning in 2025 and higher oil and gas production costs related to the ramp-up of LNG production at the GTA Phase 1 project for the nine months ended September 30, 2025.
Current wording
Net cash provided by (used in) operating activities. Net cash provided by operating activities for the three months ended March 31, 2026 was $106.6 million compared with net cash used in operating activities for the three months ended March 31, 2025 of $0.9 million. The increase in cash provided by operating activities in the three months ended March 31, 2026 when compared to the same period in 2025 is primarily a result of higher production and sales volumes at Jubilee and GTA, lower routine oil and gas production costs across all of our business units and decreased workover expense in our Gulf of America business unit, partially offset by lower average realized oil and gas prices for the three months ended March 31, 2026.
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 estimate we will spend in aggregate less than $350 million 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 in aggregate around $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 $250 million related to maintenance activities across our producing 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 producing Ghana and Gulf of America assets, including infill development drilling and TEN FPSO purchase payments;
Previous wording
•Approximately $25 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;
Previous wording
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 Company’s production assets in Ghana and Equatorial Guinea. As of September 30, 2025, borrowings under the Facility totaled approximately $1.1 billion and the undrawn availability under the Facility was $225.0 million.
Current wording
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 Company’s production assets in Ghana and Equatorial Guinea. As of March 31, 2026, borrowings under the Facility totaled approximately $1.0 billion and the undrawn availability under the Facility was $350.0 million.
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. In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes 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 thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations. We were in compliance with the financial covenants contained in the Facility as of September 30, 2025 (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. Leverage was elevated in 2025 given lower oil prices and the impact of operation costs during the ramp-up of the GTA Phase 1 project combined with lower company production. As a result, in July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment made this covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.0x and 4.25x, respectively, and thereafter returned to the originally agreed upon ratio of 3.50x for assessment dates thereafter. In February 2026, we further amended the debt cover ratio calculation through September 2026. This most recent amendment makes the covenant less restrictive for the following two scheduled financial covenant assessment dates, up to a maximum of 4.5x and 4.25x respectively, and for purposes of the financial covenant assessment date in March 2026, the calculation was made excluding the Company’s Mauritania and Senegal business unit. The debt cover ratio returns to the originally agreed upon ratio of 3.5x for assessment dates thereafter. The change was intended to align the covenant calculation with recent business operations, lower oil prices and the impact of operating costs during the ramp-up of the GTA Phase 1 project on our results of operations. The Facility contains customary cross default provisions.
Previous wording
We have four series of senior notes outstanding as of September 30, 2025, which we collectively refer to as the “Senior Notes.” Our 7.125% Senior Notes had an outstanding balance of $250.0 million as of September 30, 2025, and mature on April 4, 2026. In October 2025, we used net proceeds from the GoA Term Loan Facility, together with cash on hand, to fund the repurchase of $150.0 million of the 7.125% Senior Notes resulting in $100.0 million remaining outstanding. Interest is payable on the 7.125% Senior Notes each April 4 and October 4. Our 7.750% Senior Notes have an outstanding balance of $350.0 million and mature on May 1, 2027. 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 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 and 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 as of March 31, 2026, which we collectively refer to as the “Senior Notes.” In January 2026, we used the net proceeds of $98.5 million from funding 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. Our 7.750% Senior Notes have an outstanding balance of $100.2 million and mature on May 1, 2027. 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 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 and mature on October 1, 2031. Interest is payable on the 8.750% Senior Notes each April 1 and October 1.
Previous wording
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.
Current wording
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 GoA Term Loan Facility and, with respect to certain of our subsidiaries that own our assets in Mauritania and Senegal, 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, 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 Senior Notes on a senior, unsecured basis. 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.
Previous wording
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 structured in two tranches, with the first tranche consisting of a four-year term loan in an aggregate principal amount of $150.0 million, which was funded on October 1, 2025, and a second tranche comprising commitments to lend up to an additional $100.0 million, available for drawing until April 1, 2026. On October 1, 2025, we received net proceeds of $147.2 million from funding of the first tranche after deducting fees and other expenses. On October 6, 2025, the net proceeds were used, together with cash on hand, to fund the redemption of a portion of the 7.125% Senior Notes due 2026 totaling $150 million in aggregate. The GoA Term Loan Facility matures in 2029, with principal payments beginning June 30, 2026.
Current wording
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 structured in two tranches, with the first tranche consisting of a four-year term loan in an aggregate principal amount of $150.0 million, which was funded on October 1, 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 $250.0 million in aggregate of the 7.125% Senior Notes due in 2026. On March 24, 2026, we made a voluntary prepayment of $53.6 million against the GoA Term Loan. On May 1, 2026, the GoA Term Loan Facility was amended to apply this prepayment in full satisfaction of the scheduled principal amount due on the first scheduled amortization payment date on June 30, 2026, and then ratably to all remaining scheduled principal payments of the outstanding loans. The amendment also deferred all future scheduled amortization payment dates in 2026, 2027 and 2028 such that they will now be due on October 1, January 1, April 1 and July 1 in each of 2026, 2027 and 2028. As a result of the amendment, there is only one remaining scheduled amortization payment in 2026 to be paid on October 1, 2026.
Previous wording
(5)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 commitment to be approximately $126.1 million as of September 30, 2025, net to Kosmos, which will be funded annually by Kosmos over an estimated 11 year period. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.
Current wording
(5)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 commitment to be approximately $111.0 million as of March 31, 2026, net to Kosmos, which will be funded annually by Kosmos over an estimated fourteen year period. It is possible that our funding requirements could change based on future changes in the decommissioning plan or estimates.
Previous wording
As of September 30, 2025, we have a commitment to drill one development well in Equatorial Guinea.
Current wording
As of March 31, 2026, we have a commitment to drill one development well related to our assets held for sale 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
Once the Tortue Phase 1 SPA Commercial Operations Date is achieved, 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 wording
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.
Previous wording
We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and gas reserves, asset retirement obligations and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. Other than items discussed in Note 2 — Accounting Policies, there have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended December 31, 2024.
Current wording
We consider accounting policies related to our revenue recognition, exploration and development costs, income taxes, estimates of proved oil and gas reserves, asset retirement obligations, impairment of long-lived assets, and acquisition accounting as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. Other than items discussed in Note 2 — Accounting Policies, there have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended December 31, 2025.
Previous wording
•the impacts of the continued war in Ukraine and ongoing instability in the Middle East and the effects these events have on the oil and gas industry as a whole, including increased volatility with respect to oil, natural gas and LNG prices and operating and capital expenditures;
Current wording
•the impacts of the conflict in Iran and ongoing instability in the Middle East and Latin America, the continued war in Ukraine and the effects these events have on the oil and gas industry as a whole, including increased volatility with respect to oil, natural gas and liquified natural gas (“LNG”) prices and operating and capital expenditures;
Rearranged previous paragraphs (3)
Previous report — wording carried elsewhere
Derivatives, net. During the nine months ended September 30, 2025 and 2024, we recorded a gain of $18.5 million and a loss of $5.7 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.
Previous report — wording carried elsewhere
As of September 30, 2025, borrowings under the Facility totaled approximately $1.1 billion and the undrawn availability under the Facility was $225.0 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. In July 2025, the Company and the Facility lenders agreed to amend the debt cover ratio required under the Facility. The amendment makes 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 thereafter returns to the originally agreed upon ratio of 3.50x for assessment dates thereafter. The change is intended to align the covenant calculation with recent business operations, lower oil prices and the impact of pre-production operating costs associated with the GTA Phase 1 project on our results of operations.
Previous report — wording carried elsewhere
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 structured in two tranches, with the first tranche consisting of a four-year term loan in an aggregate principal amount of $150.0 million, which was funded on October 1, 2025, and a second tranche comprising commitments to lend up to an additional $100.0 million, available for drawing until April 1, 2026. On October 1, 2025, we received net proceeds of $147.2 million from funding of the first tranche after deducting fees and other expenses. On October 6, 2025, the net proceeds were used, together with cash on hand, to fund the redemption of a portion of the 7.125% Senior Notes due 2026 totaling $150.0 million in aggregate. The proceeds from any additional borrowings on the GoA Term Loan Facility is expected be used to fund the redemption or repayment of the company’s Senior Notes.