Kosmos Energy Ltd.
03/02/2026 | Press release | Distributed by Public on 03/02/2026 14:05
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including, without limitation, those set forth in "Cautionary Statement Regarding Forward-Looking Statements" and "Item 1A. Risk Factors." The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes thereto included elsewhere in this annual report on Form 10-K.
Overview
Kosmos Energy is a leading deepwater exploration and production company focused on meeting the world's growing demand for energy. We have diversified oil and gas production from assets offshore Ghana, Equatorial Guinea, Mauritania, Senegal, and the Gulf of America. Additionally, in the proven basins where we operate we are advancing high-quality development opportunities, which have come from our exploration success.
Recent Developments
Corporate
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.
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.
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.
Ghana
During the year ended December 31, 2025, Ghana production averaged approximately 93,100 Boepd gross (31,100 Boepd net).
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.
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
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.
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.
Gulf of America
During the year ended December 31, 2025, Gulf of America production averaged approximately 17,600 Boepd (net) (~84% oil).
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.
In January 2026, Kosmos was awarded two lease blocks in the Gulf of America Big Beautiful Gulf Lease Sale 1 ("BBG1").
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.
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.
Equatorial Guinea
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.
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.
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.
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.
In February 2026, we notified our partners that we are withdrawing from Block EG-01.
In the fourth quarter of 2024, the corporate tax rate in Equatorial Guinea was reduced from 35% to 25%, with an effective date of January 1, 2025.
Mauritania and Senegal
Greater Tortue Ahmeyim Project
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.
Yakaar and Teranga Discoveries
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.
Sao Tome and Principe
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.
Results of Operations
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.
| Years ended December 31, | |||||||||||||||||
|
2025
|
2024
|
2023
|
|||||||||||||||
| (In thousands, except per volume data) | |||||||||||||||||
| Sales volumes: | |||||||||||||||||
| Oil (MBbl) | 16,452 | 20,472 | 20,385 | ||||||||||||||
| Gas (MMcf) | 32,280 | 16,180 | 13,737 | ||||||||||||||
| NGL (MBbl) | 582 | 338 | 382 | ||||||||||||||
| Total (MBoe) | 22,414 | 23,507 | 23,057 | ||||||||||||||
| Total (Boepd) | 61,408 | 64,226 | 63,168 | ||||||||||||||
| Revenues: | |||||||||||||||||
| Oil sales | $ | 1,100,483 | $ | 1,611,169 | $ | 1,658,421 | |||||||||||
| Gas sales | 170,548 | 57,243 | 35,307 | ||||||||||||||
| NGL sales | 17,321 | 6,946 | 7,880 | ||||||||||||||
| Total revenues | $ | 1,288,352 | $ | 1,675,358 | $ | 1,701,608 | |||||||||||
| Average oil sales price per Bbl | $ | 66.89 | $ | 78.70 | $ | 81.35 | |||||||||||
| Average gas sales price per Mcf | 5.28 | 3.54 | 2.57 | ||||||||||||||
| Average NGL sales price per Bbl | 29.76 | 20.55 | 20.61 | ||||||||||||||
| Average total sales price per Boe | 57.48 | 71.27 | 73.80 | ||||||||||||||
| Costs: | |||||||||||||||||
| Oil and gas production, excluding workovers | $ | 686,039 | $ | 490,860 | $ | 367,375 | |||||||||||
| Oil and gas production, workovers | 22,863 | 39,654 | 22,722 | ||||||||||||||
| Total oil and gas production costs | $ | 708,902 | (1) | $ | 530,514 | (1) | $ | 390,097 | |||||||||
| Depletion, depreciation and amortization | $ | 556,774 | $ | 456,774 | $ | 444,927 | |||||||||||
| Average cost per Boe: | |||||||||||||||||
| Oil and gas production, excluding workovers | $ | 30.61 | $ | 20.88 | $ | 15.93 | |||||||||||
| Oil and gas production, workovers | 1.02 | 1.69 | 0.99 | ||||||||||||||
| Total oil and gas production costs | 31.63 | (1) | 22.57 | (1) | 16.92 | ||||||||||||
| Depletion, depreciation and amortization | 24.84 | 19.43 | 19.30 | ||||||||||||||
| Total oil and gas production costs, depletion, depreciation and amortization | $ | 56.47 | $ | 42.00 | $ | 36.22 | |||||||||||
(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.
The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.
Year Ended December 31, 2025 vs. 2024
| Years Ended December 31, | Increase | ||||||||||||||||
| 2025 | 2024 | (Decrease) | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Oil and gas revenue | $ | 1,288,352 | $ | 1,675,358 | $ | (387,006) | |||||||||||
| Gain on sale of assets | 2,200 | - | 2,200 | ||||||||||||||
| Other income, net | 1,098 | 204 | 894 | ||||||||||||||
| Total revenues and other income | 1,291,650 | 1,675,562 | (383,912) | ||||||||||||||
| Costs and expenses: | |||||||||||||||||
| Oil and gas production | 708,902 | 530,514 | 178,388 | ||||||||||||||
| Exploration expenses | 223,616 | 119,907 | 103,709 | ||||||||||||||
| General and administrative | 76,120 | 100,155 | (24,035) | ||||||||||||||
| Depletion, depreciation and amortization | 556,774 | 456,774 | 100,000 | ||||||||||||||
| Impairment of long-lived assets | 177,563 | - | 177,563 | ||||||||||||||
| Interest and other financing costs, net | 223,430 | 88,598 | 134,832 | ||||||||||||||
| Derivatives, net | (53,665) | 12,099 | (65,764) | ||||||||||||||
| Other expenses, net | 13,491 | 17,703 | (4,212) | ||||||||||||||
| Total costs and expenses | 1,926,231 | 1,325,750 | 600,481 | ||||||||||||||
| Income (loss) before income taxes | (634,581) | 349,812 | (984,393) | ||||||||||||||
| Income tax expense | 65,205 | 159,961 | (94,756) | ||||||||||||||
| Net income (loss) | $ | (699,786) | $ | 189,851 | $ | (889,637) | |||||||||||
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.
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.
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.
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.
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.
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.
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.
Liquidity and Capital Resources
We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to our strategy as a deepwater exploration and production company. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt, as well as partner carries.
Oil prices are historically volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This oil price volatility could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program and our current liquidity position is expected to support our capital program for 2026.
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.
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.
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.
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.
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the years ended December 31, 2025, 2024 and 2023:
| Years Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Sources of cash, cash equivalents and restricted cash: | |||||||||||||||||
| Net cash provided by operating activities | $ | 134,012 | $ | 678,249 | $ | 765,170 | |||||||||||
| Net proceeds from issuance of senior notes | - | 885,285 | - | ||||||||||||||
| Borrowings under long-term debt | 675,000 | 325,000 | 300,000 | ||||||||||||||
| 809,012 | 1,888,534 | 1,065,170 | |||||||||||||||
| Uses of cash, cash equivalents and restricted cash: | |||||||||||||||||
| Oil and gas assets | 314,408 | 933,659 | 932,603 | ||||||||||||||
|
Notes receivable and other investing activities
|
86,791 | 32,397 | 62,247 | ||||||||||||||
| Payments on long-term debt | 225,000 | 350,000 | 145,000 | ||||||||||||||
| Purchase of capped call transactions | - | 49,800 | - | ||||||||||||||
| Repurchase and redemption of senior notes | 150,000 | 499,515 | - | ||||||||||||||
| Dividends | - | - | 166 | ||||||||||||||
|
Other financing costs
|
346 | 36,647 | 13,214 | ||||||||||||||
| 776,545 | 1,902,018 | 1,153,230 | |||||||||||||||
| Increase (decrease) in cash, cash equivalents and restricted cash | $ | 32,467 | $ | (13,484) | $ | (88,060) | |||||||||||
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.
The following table presents our liquidity and financial position as of December 31, 2025 and 2024:
| Years Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
|
Outstanding debt principal balances:
|
|||||||||||
| Facility(2) | $ | 1,200,000 | $ | 900,000 | |||||||
|
7.125% Senior Notes(1)
|
100,000 | 250,000 | |||||||||
| 7.750% Senior Notes(2) | 350,000 | 350,000 | |||||||||
| 7.500% Senior Notes | 400,274 | 400,274 | |||||||||
| 8.750% Senior Notes | 500,000 | 500,000 | |||||||||
| 3.125% Convertible Senior Notes | 400,000 | 400,000 | |||||||||
| GoA Term Loan Facility(1) | 150,000 | - | |||||||||
| Total long-term debt | $ | 3,100,274 | $ | 2,800,274 | |||||||
| Cash and cash equivalents | 91,518 | 84,972 | |||||||||
| Total restricted cash(3) | 26,226 | 305 | |||||||||
|
Net debt
|
$ | 2,982,530 | $ | 2,714,997 | |||||||
|
Availability under the Facility(2)
|
$ | 150,000 | $ | 450,000 | |||||||
| Availability under the GoA Term Loan Facility(1) | $ | 100,000 | $ | - | |||||||
| Available borrowings plus cash and cash equivalents | $ | 341,518 | $ | 534,972 | |||||||
(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.
(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.
(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
Capital Expenditures and Investments
We expect to incur capital costs as we:
•drill additional infill wells in Ghana and the Gulf of America;
•advance development efforts in the Gulf of America and in Mauritania and Senegal; and
•execute facilities integrity activities in Equatorial Guinea.
We have relied on a number of assumptions in budgeting for our future activities. These include the number of wells we plan to drill, our paying interests in our operations including disproportionate payment amounts, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects, the availability of suitable equipment and qualified personnel and our cash flows from operations. We also evaluate potential corporate and asset acquisition 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.
2026Capital Program
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:
•Approximately $275 million related to maintenance activities across our Ghana and Gulf of America assets, including infill development drilling and TEN FPSO purchase payments;
•Approximately $60 million related to progressing our development programs in the Gulf of America and in Mauritania and Senegal; and
•Approximately $15 million related to facilities integrity activities in Equatorial Guinea.
The ultimate amount of capital we will spend may fluctuate materially based on market conditions and the success of our exploitation and drilling results among other factors. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil, natural gas, and LNG and the prices we receive from the sale of oil, natural gas and LNG, and our ability to effectively hedge future production volumes, the success of our multi-faceted infrastructure-led exploration, appraisal, and development drilling programs, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, our partners' alignment with respect to capital plans, and the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.
Significant Sources of Capital
Facility
The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. The amount of funds available to be borrowed under the Facility, also known as the borrowing base amount, is determined every March and September. The borrowing base amount is based on the sum of the net present values of net cash flows and relevant capital expenditures reduced by certain percentages as well as value attributable to certain assets' reserves and/or resources in the Jubilee and TEN Fields in Ghana and the Ceiba Field and Okume Complex in Equatorial Guinea.
In 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.
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility expires one month prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on April 1, 2027, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of December 31, 2029. As of December 31, 2025, we had no letters of credit issued under the Facility. We have the right to cancel all the undrawn commitments under the amended and restated Facility.
If an event of default exists under the Facility, the lenders can accelerate the maturity and exercise other rights and remedies, including the enforcement of security granted pursuant to the Facility over certain assets held by our subsidiaries. We were in compliance with the financial covenants contained in the Facility, as amended, as of September 30, 2025 (the most recent assessment date). The Facility contains customary cross default provisions.
The U.S. and many foreign economies continue to experience uncertainty driven by varying macroeconomic conditions. Although some of these economies have shown signs of improvement, macroeconomic recovery remains uneven. Uncertainty in the macroeconomic environment and associated global economic conditions have resulted in extreme volatility in credit, equity, and foreign currency markets, including the European sovereign debt markets and volatility in various other markets. If any of the financial institutions within our Facility are unable to perform on their commitments, our liquidity could be impacted. We actively monitor all of the financial institutions participating in our Facility. None of the financial institutions have indicated to us that they may be unable to perform on their commitments. In addition, we periodically review our banking
and financing relationships, considering the stability of the institutions and other aspects of the relationships. Based on our monitoring activities, we currently believe our banks will be able to perform on their commitments.
Senior Notes
We have 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.
The Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equally in right of payment with all of its existing and future senior indebtedness (including the 3.125% Convertible Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility). The Senior Notes are jointly and severally guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company's Gulf of America assets, and on a subordinated, unsecured basis by entities that borrow under, or guarantee, our Facility.
3.125% Convertible Senior Notes due 2030
We have one series of senior convertible notes outstanding. Our 3.125% Convertible Senior Notes mature on March 15, 2030, unless earlier converted, redeemed or repurchased. Interest is payable in arrears each March 15 and September 15, commencing September 15, 2024.
The 3.125% Convertible Senior Notes are senior, unsecured obligations of Kosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including the Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility, to the extent of the value of the assets securing such indebtedness). The 3.125% Convertible Senior Notes are guaranteed on a senior, unsecured basis by certain of our existing subsidiaries that guarantee on a senior basis the Senior Notes, and, in certain circumstances, certain of our existing future subsidiaries. The 3.125% Convertible Senior Notes are guaranteed on a subordinated, unsecured basis by certain of our existing subsidiaries that borrow under or guarantee the Facility and guarantee on a subordinated basis the Senior Notes, and, in certain circumstances, certain of our existing or future subsidiaries.
The 3.125% Convertible Senior Notes indenture contains customary terms and covenants.
In connection with the issuance of the 3.125% Convertible Senior Notes, the Company entered into capped call transactions (the "Capped Call Transactions"). The Capped Call Transactions are generally expected to reduce potential dilution to holders of our common stock upon any conversion of the 3.125% Convertible Senior Notes and/or offset any cash payments that we are required to make in excess of the principal amount of any 3.125% Convertible Senior Notes that are converted, as the case may be, with such reduction and/or offset subject to a cap.
GoA Term Loan Facility
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.
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.
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:
•the GoA field life coverage ratio (as defined in the glossary), not less than 1.50x; and
•the GoA net leverage ratio (as defined in the glossary), not more than 3.50x
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.
GTA Nordic Bonds
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.
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.
Contractual Obligations
The following table presents maturities by expected debt maturity dates, the weighted-average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the instrument's estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account amortization of deferred financing costs.
| Years Ending December 31, |
Asset (Liability) Fair Value at December 31, |
||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | 2025 | ||||||||||||||||||||||||||||||||||||||||
| (In thousands, except percentages) | |||||||||||||||||||||||||||||||||||||||||||||||
| Fixed rate debt: | |||||||||||||||||||||||||||||||||||||||||||||||
|
7.125% Senior Notes(5)
|
$ | 100,000 | $ | - | $ | - | $ | - | $ | - | $ | - | $ | 100,000 | $ | 99,303 | |||||||||||||||||||||||||||||||
|
7.750% Senior Notes(6)
|
- | 350,000 | - | - | - | - | 350,000 | 321,394 | |||||||||||||||||||||||||||||||||||||||
| 7.500% Senior Notes | - | - | 400,274 | - | - | - | 400,274 | 270,125 | |||||||||||||||||||||||||||||||||||||||
|
8.750% Senior Notes
|
- | - | - | - | - | 500,000 | 500,000 | 283,575 | |||||||||||||||||||||||||||||||||||||||
|
3.125% Convertible Senior Notes
|
- | - | - | - | 400,000 | - | 400,000 | 172,704 | |||||||||||||||||||||||||||||||||||||||
| Variable rate debt: | |||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average interest rate | 8.15 | % | 8.24 | % | 8.91 | % | 9.34 | % | - | % | - | % | |||||||||||||||||||||||||||||||||||
|
Facility(1)(6)
|
$ | - | $ | 320,449 | $ | 385,508 | $ | 494,043 | $ | - | $ | - | $ | 1,200,000 | 1,200,000 | ||||||||||||||||||||||||||||||||
|
GoA Term Loan Facility(5)
|
32,143 | 42,857 | 42,857 | 32,143 | - | - | 150,000 | 150,000 | |||||||||||||||||||||||||||||||||||||||
|
Total principal debt repayments
|
$ | 132,143 | $ | 713,306 | $ | 828,639 | $ | 526,186 | $ | 400,000 | $ | 500,000 | $ | 3,100,274 | |||||||||||||||||||||||||||||||||
| Interest & commitment fees on long-term debt | 229,905 | 203,158 | 140,351 | 87,655 | 50,000 | 43,750 | 754,819 | ||||||||||||||||||||||||||||||||||||||||
|
Operating leases(2)
|
3,923 | 3,956 | 3,744 | 3,176 | - | - | 14,799 | ||||||||||||||||||||||||||||||||||||||||
|
Purchase obligations(3)
|
18,702 | - | - | - | - | - | 18,702 | ||||||||||||||||||||||||||||||||||||||||
|
Decommissioning trust funds(4)
|
11,598 | 8,284 | 8,284 | 8,284 | 8,284 | 77,865 | 122,599 | ||||||||||||||||||||||||||||||||||||||||
|
Firm transportation commitments
|
4,180 | 2,363 | - | - | - | - | 6,543 | ||||||||||||||||||||||||||||||||||||||||
______________________________________
(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of December 31, 2025. Any increases or decreases in the level of borrowings or increases or decreases in the available borrowing base would impact the scheduled maturities of debt during the next five years and thereafter.
(2)Primarily relates to corporate office and foreign office leases.
(3)Represents gross contractual obligations to execute planned future capital projects. Other joint owners in the properties operated by Kosmos will be billed for their working interest share of such costs. Does not include our share of operator's purchase commitments for jointly owned fields and facilities where we are not the operator and excludes commitments for exploration activities, including well commitments and seismic obligations, in our petroleum contracts. The Company's liabilities for asset retirement obligations associated with the dismantlement, abandonment and restoration costs of oil and gas properties are not included. See Note 11-Asset Retirement Obligations of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding these liabilities.
(4)In April 2024, a decommissioning trust agreement with the Jubilee unit partners to cash fund future retirement costs associated with the Jubilee Field was finalized. The operator currently estimates the total remaining commitment to be approximately $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.
(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.
(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.
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.
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.
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.
Critical Accounting Policies
This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities as of the date the financial statements are available to be issued. These estimates could change materially if different information or assumptions were used. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in "Item 8. Financial Statements and Supplementary Data-Note 2-Accounting Policies." We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.
Revenue Recognition.We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2025 and 2024, we had no oil and gas imbalances recorded in our consolidated financial statements.
Our oil and gas revenues are recognized when hydrocarbons have been sold to a purchaser at a fixed or determinable price, title has transferred and collection is probable. Certain revenues are based on contracts with provisional pricing and quantity optionality which contain a derivative that is separated from the host contract for accounting purposes. The host contract is the receivable from sales at the spot price on the date of sale. The derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Exploration and Development Costs.We follow the successful efforts method of accounting for our oil and gas properties. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when a determination that proved reserves have been found. Exploration costs, including geological and geophysical costs and costs of carrying unproved properties, are expensed as incurred. Exploratory drilling costs are capitalized when incurred. If exploratory wells are determined to be commercially unsuccessful or dry holes, the applicable costs are expensed and recorded in exploration expense on the consolidated statement of operations. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and natural gas to the surface are expensed as oil and gas production expense.
Income Taxes.We account for income taxes as required by the ASC 740-Income Taxes ("ASC 740"). We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal, state and international tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of changes in tax laws or tax rates, tax credits, and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we must record a valuation allowance against such deferred tax assets for the amount we
would not expect to recover, which would result in no benefit for the deferred tax amounts. As of December 31, 2025 and 2024, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.
ASC 740 provides a more-likely-than-not standard in evaluating whether a valuation allowance is necessary after weighing all of the available evidence. When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following:
•the status of our operations in the particular taxing jurisdiction, including whether we have commenced production from a commercial discovery;
•whether a commercial discovery has resulted in significant proved reserves that have been independently verified;
•the amounts and history of taxable income or losses in a particular jurisdiction;
•projections of future income, including the sensitivity of such projections to changes in production volumes and prices;
•the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward in a jurisdiction; and
•the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets.
Estimates of Proved Oil and Gas Reserves.Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and assessment of impairment of our oil and natural gas properties. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Proved reserve quantities and future cash flows are estimated by independent petroleum engineering consultants and prepared in accordance with guidelines established by the SEC and the FASB. The accuracy of these reserve estimates is a function of:
•the engineering and geological interpretation of available data;
•estimates of the amount and timing of future operating cost, production taxes, development cost and workover cost;
•the accuracy of various mandated economic assumptions; and
•the judgments of the persons preparing the estimates.
Asset Retirement Obligations.We account for asset retirement obligations as required by ASC 410 - Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long-lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset's acquisition or in service date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long-lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations. Estimating the future restoration and removal costs requires management to make estimates and judgments because most of the removal obligations are many years in the future and the regulations in some countries that we operate often have vague descriptions of what constitutes removal. Additionally, asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is made to the oil and gas property balance.
Impairment of Long-lived Assets.We review our long-lived assets for impairment when changes in circumstances indicate that the carrying amount of an asset may not be recoverable. ASC 360 - Property, Plant and Equipment requires an impairment loss to be recognized if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. That assessment shall be based on the carrying amount of the asset at the date it is tested for recoverability, whether in use or under development. Assets to be disposed of and assets not expected to provide any future service potential to us are recorded at the lower of carrying amount or fair value. Oil and gas properties are grouped in accordance with ASC 932 - Extractive Activities-Oil and Gas. The basis for grouping is a reasonable aggregation of properties typically by field or by logical grouping of assets with significant shared infrastructure.
For long-lived assets whereby the carrying value exceeds the estimated future undiscounted cash flows, the carrying amount is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 - Fair Value Measurement. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental assessments of future production, pricing estimates, capital and operating costs, market-based weighted average cost of capital, and risk adjustment factors applied to reserves. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted-average cost of capital. Although we base the fair value estimate of each asset group on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserve quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.
We believe the assumptions used in our analysis to test for impairment are appropriate and result in a reasonable estimate of future cash flows and fair value. Kosmos has consistently used an average of third-party industry forecasts to determine our pricing assumptions. Where unproved reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the evaluation.
Acquisition Accounting. The purchase price in an acquisition (business combination or asset acquisition) is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the deal announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired, and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain.
New Accounting Pronouncements
See "Item 8. Financial Statements and Supplementary Data-Note 2-Accounting Policies" for a discussion of recent accounting pronouncements.
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