Kosmos Energy Ltd. (KOS) FY 2022 MD&A

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

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

Overview

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

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

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Recent Developments

Corporate

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

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

Ghana

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

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

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

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

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

U.S. Gulf of Mexico

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

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

In June 2022, Kosmos completed the acquisition of an additional 5.9% interest in the Kodiak oil field from Marubeni by exercising our preferential right to purchase for a total purchase price of approximately $29.0 million. As a result of the transaction, our working interest increased from 29.1% to 35.0%.

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

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

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

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

Equatorial Guinea

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

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

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

In October 2022, we entered into a farm-out agreement with Panoro Energy ASA (Panoro) to farm-out a 6.0% participating interest in Block S offshore Equatorial Guinea, which will result in our participating interest in Block S reducing to 34.0%. The transaction is awaiting governmental approvals. During the fourth quarter of 2022, we received approval from the Government of Equatorial Guinea to enter the second sub-period phase of the Block S exploration license with a scheduled expiration in December 2024. During 2023, Kosmos and partners plan to progress the infrastructure-led exploration prospect, Akeng Deep in Block S for drilling in early 2024.

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

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

Mauritania and Senegal

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

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

Greater Tortue Ahmeyim Unit

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

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

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

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

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

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

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

Sao Tome and Principe

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

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Results of Operations

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

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

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

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

Year Ended December 31, 2022 vs. 2021

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

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

Sources and Uses of Cash

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

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

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

Capital Expenditures and Investments

We expect to incur capital costs as we:

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

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

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

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

2023 Capital Program

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

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

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

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

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

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

Significant Sources of Capital

Facility

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

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

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

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

Corporate Revolver

On March 31, 2022, we refinanced the Corporate Revolver by replacing it with a new revolving credit facility agreement resulting in the following changes to the terms:

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

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

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

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

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

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

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

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

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

Senior Notes

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

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

GoM Term Loan

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

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

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

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Contractual Obligations

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

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(1)The amounts included in the table represent principal maturities only. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the available borrowing base as of December 31, 2022. 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 of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding these liabilities.

We currently have a commitment to drill three development wells and one exploration well in Equatorial Guinea. In Mauritania and Senegal, we have a $200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue FPSO.

In February 2019, Kosmos and BP signed Carry Advance Agreements with the national oil companies of Mauritania and Senegal, which obligate us separately to finance the respective national oil companies’ share of certain development costs. Kosmos’ total share for the two agreements combined is currently estimated at approximately $240.0 million, of which $196.9 million has been incurred through December 31, 2022, excluding accrued interest. These amounts will be repaid through the national oil companies’ share of future revenues.

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Critical Accounting Policies

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

Revenue Recognition. We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2022 and 2021, 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 provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded 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, 2022 and 2021, we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

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

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

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

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

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

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

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

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

•the engineering and geological interpretation of available data;

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

•the accuracy of various mandated economic assumptions; and

•the judgments of the persons preparing the estimates.

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

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

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

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

New Accounting Pronouncements

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