Kosmos Energy Ltd. (KOS) FY 2021 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 Atlantic Margins. Our key assets include production offshore Ghana, Equatorial Guinea and the U.S. Gulf of Mexico, as well as a world-class gas development offshore Mauritania and Senegal. We also maintain a sustainable proven basin exploration program in Equatorial Guinea, Ghana and the U.S. Gulf of Mexico.

The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in travel restrictions, including border closures, travel bans, social distancing restrictions, various quarantine measures and office closures being ordered in the various countries in which we operate, impacting some of our business operations. These ongoing restrictions have had an impact on the supply chain, resulting in the delay of various operational projects. Globally, the impact of COVID-19 has impacted demand for oil, which also resulted in significant variations in oil prices. The Company’s revenues, earnings, cash flows, capital investments, debt capacity and, ultimately, future rate of growth are highly dependent on oil prices.

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Recent Developments

Corporate

In March 2021, the Company issued $450.0 million of 7.500% Senior Notes due 2028 and received net proceeds of approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general corporate purposes.

In May 2021, the Company entered into an amended and restated Facility Agreement and certain ancillary documents. As part of the amendment, Kosmos elected to lower the overall Facility size from $1.5 billion to $1.25 billion to reduce reliance on the Facility and commitment costs following the completion of the Company’s senior notes issuance in March 2021. The amendment includes a two-year tenor extension, with the Facility’s final maturity now in March 2027. As amended, the Facility has an available borrowing base of approximately $1.24 billion.

In October 2021, Kosmos completed the acquisition of Anadarko WCTP Company (“Anadarko WCTP”), a subsidiary of Occidental Petroleum Corporation, which owns a participating interest in the WCTP Block and DT Block offshore Ghana, including an 18.0% participating interest in the Jubilee Unit Area and an 11.1% participating interest in the TEN fields. In consideration for the acquisition, Kosmos paid $455.9 million in cash based on an initial purchase price of $550.6 million reduced by certain purchase price adjustments totaling $94.7 million. Additionally, we incurred $9.5 million of transaction related costs, which were capitalized as part of the purchase price. Following closing of the acquisition, Kosmos’ interest in the Jubilee Unit Area increased from 24.1% to 42.1%, and Kosmos’ interest in the TEN fields increased from 17.0% to 28.1%.

Under the Deepwater Tano Block Joint Operating Agreement, certain joint venture partners have pre-emption rights that, if fully exercised, could reduce our ultimate interest in the Jubilee Unit Area by 3.8% to 38.3%, and our ultimate interest in the TEN fields by 8.3% to 19.8%. In November 2021, we received notice from certain joint venture partners that they intend to exercise their pre-emption rights in relation to Kosmos' acquisition of additional interests in Ghana. The exercise of pre-emption rights is subject to finalizing definitive agreements with Kosmos and requires approval from GNPC and the Ghanaian Ministry of Energy. The initial purchase price for the pre-empted portion of transaction is approximately $150 million and is subject to additional purchase price closing adjustments. Kosmos would anticipate using any potential proceeds to accelerate debt repayment.

Kosmos initially funded the purchase price through the issuance of $400.0 million aggregate principal amount of floating rate senior notes due 2022 (“Bridge Notes”) and $75.0 million of borrowings under Kosmos' Facility. Kosmos then refinanced the Bridge Notes in full with the proceeds from the issuance of $400.0 million of 7.750% Senior Notes due 2027 and cash on hand. Kosmos also received $136.6 million in proceeds from a public issuance of 43.1 million shares of Kosmos’ common stock with proceeds used to repay a portion of outstanding borrowings under the Facility during the fourth quarter of 2021.

Under the terms of our 2020 farm-out agreement, 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. In February 2022, there was an oil discovery announced in Namibia on the first well drilled. Under the terms of Shell’s Petroleum Agreement with Namibia, if Shell decides to appraise the discovery, an appraisal plan is required to be submitted within 150 days from completion of tests on the discovery well.

Ghana

During the year ended December 31, 2021, Ghana production averaged approximately 107,700 Bopd gross (26,100 Bopd net) including activity related to our acquisition of additional interests in Ghana commencing October 13, 2021, the acquisition date. Jubilee production averaged approximately 74,900 Bopd gross (20,200 Bopd net) with consistent water injection and gas offtake and TEN production averaged approximately 32,800 Bopd gross (5,900 Bopd net). The Ghana Jubilee catenary anchor leg mooring (“CALM”) buoy was installed and commissioned in February 2021.

In April 2021, operations re-commenced on a multi-year development drilling program. One Jubilee producer well started production in July 2021 and one Jubilee injector well came online in September 2021. In the fourth quarter of 2021, a TEN gas injector well and a second Jubilee producer well were successfully completed and brought online in addition to the

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recompletion of a Jubilee water injection well. The rig has continued drilling operations for the multi-year infill development drilling program in 2022, which is expected to include the drilling and completion of two water-injection wells and one producer well in Jubilee and at TEN plans are to drill three development producer wells, one of which is expected to be completed in 2022, and complete one water-injector well in 2022.

U.S. Gulf of Mexico

During the year ended December 31, 2021, U.S. Gulf of Mexico production averaged approximately 19,700 Boepd (net) (~82% oil). The impact of the unplanned downtime from hurricanes to our production in the U.S. Gulf of Mexico was approximately 1,000 barrels of oil equivalent per day for the full year ended December 31, 2021 compared to our previous production forecasts for 2021. Production returned to around pre-hurricane levels in early fourth quarter of 2021.

In April 2021, the Kodiak #3 infill well located in Mississippi Canyon Block 727 (29.1% working interest) was brought online with one of two zones intermittently producing. During the third quarter of 2021, the well continued to experience production issues and was shut-in. Late in the first quarter of 2022, the Company plans to commence operations to side-track the original Kodiak #3 well, which is expected to be online in the third quarter of 2022, with insurance proceeds expected to cover the costs incurred to return the Kodiak #3 well to normal operations.

During the second quarter of 2021, the Tornado-5 infill well located in the Green Canyon Block 281 (35.0% working interest) was successfully drilled and completed. The Tornado-5 well was brought online in July 2021 and is performing at the top end of expectations.

In January 2021, we announced the Winterfell-1 exploration well encountered approximately 26 meters (85 feet) of net oil pay in two intervals. Winterfell-1 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.

In July 2021, the Company drilled the Zora infrastructure-led exploration prospect located in DeSoto Canyon Block 266 (37.5% working interest). The well did not find hydrocarbons and was plugged and abandoned in August 2021. The well results are being integrated into the ongoing evaluation of the surrounding area. The Company recorded approximately $14.6 million of exploration expense for the year ended December 31, 2021 related to the well.

Equatorial Guinea

Production in Equatorial Guinea averaged approximately 29,900 Bopd gross (9,700 Bopd net) for the year ended December 31, 2021. Two of three planned infill wells in the Okume Complex were drilled and came online during the fourth quarter of 2021. The third planned well has been deferred, as the rig was utilized to plug and abandon an existing well in Equatorial Guinea and then mobilized to its next contract before it could complete the drilling of the last well.

Mauritania and Senegal

Greater Tortue Ahmeyim Unit

In July 2021, project partners received notice that the delivery of the Tortue FPSO is likely to be delayed due to COVID-19 related labor shortages in China following a ramp up in activity at the shipyard. First gas from Phase 1 of the Greater Tortue project is now expected in the third quarter of 2023, with the project making steady progress during 2021. The following milestones were achieved through the year-end and filing date:

•FLNG: All four mixed refrigerant compressors lifted onboard and the pipe rack installation operations commenced

•FPSO: The last four of the eight process modules were successfully lifted onto the FPSO deck

•Breakwater: Completed fabrication of the 21st caisson (of 21) with 16 installed

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•Subsea: The pipe laying vessel completed its nautical trials in the North Sea in preparation for the offshore installation campaign in the second quarter of 2022

In August 2021, BP, as the operator of the Greater Tortue project (“BP Operator”), with the consent of the Greater Tortue Unit participants and the respective States, agreed to sell the Greater Tortue FPSO (which is currently under construction by Technip Energies in China) to an affiliate of BP (“BP Buyer”). The Greater Tortue FPSO will be leased back to BP Operator under a long-term lease agreement, for exclusive use in the Greater Tortue project. BP Operator will continue to manage and supervise the construction contract with Technip Energies. Delivery of the Greater Tortue FPSO to BP Buyer will occur after construction is complete and the Greater Tortue FPSO has been commissioned, with the lease to BP Operator becoming effective on the same date, currently estimated to be in the third quarter of 2023.

As a result of the above transactions entered into by BP Operator, Kosmos recognized a Long-term receivable of $200.2 million from BP Operator for our share of the consideration paid from BP Buyer to and held by BP Operator as well as a $200.2 million FPSO Contract Liability in Other long-term liabilities related to the deferred sale of the Tortue FPSO. This Long-term receivable will be non-cash settled against obligations payable to BP Operator. During the year ended December 31, 2021, BP Operator settled our payment obligations of $132.4 million of capital expenditures and $42.7 million of existing Accounts Payable to BP Operator.

During the first quarter of 2021, BP, as the operator of the Cayar block offshore Senegal, provided notice to the Government of Senegal requesting an extension of the current license phase in order to provide the block owners additional time to evaluate the natural gas market for the natural gas discoveries at Yakaar-Teranga. In July 2021 a presidential decree was issued extending the term of the license for up to an additional three years. In 2021, at the conclusion of the second exploration period, Block C13 offshore Mauritania was relinquished.

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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, 2021, 2020 and 2019 are included in the following tables. For a discussion of the year ended December 31, 2020 compared to the year ended December 31, 2019, 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, 2020.

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

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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, 2021 vs. 2020

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

Oil and gas revenue. Oil and gas revenue increased by $528.0 million as a result of higher oil prices, which was partially offset by lower sales volumes during 2021 across our portfolio. Additionally, we had two liftings after the acquisition date related to our acquisition of additional interests in Ghana during the fourth quarter of 2021. We sold 19,850 MBoe at an average realized price per barrel of oil equivalent of $67.10 in 2021 and 22,111 MBoe at an average realized price per barrel of oil equivalent of $36.36 in 2020.

Gain on sale of assets. In December 2020, we closed a farm-out agreement with Shell for a portfolio of frontier exploration assets in blocks offshore Sao Tome and Principe, Suriname, and Namibia. As part of the transaction, we received proceeds in excess of our book basis resulting in a gain of approximately $92.1 million.

Oil and gas production. Oil and gas production costs increased by $7.5 million during the year ended December 31, 2021 as compared to the year ended December 31, 2020 as a result of two additional liftings related to our acquisition of additional interests in Ghana during the fourth quarter of 2021 in addition to higher production costs per barrel from the TEN fields offshore Ghana, field production mix in the U.S. Gulf of Mexico, and additional workover activity in 2021.

Facilities insurance modifications, net. Facilities insurance modifications, net decreased by $14.7 million during the year ended December 31, 2021 as compared to the year ended December 31, 2020 as the catenary anchor leg mooring (“CALM”) Buoy, the final phase of the long-term solution to the Jubilee turret remediation project, was installed and commissioned in February 2021.

Exploration expenses. Exploration expenses decreased by $19.2 million during the year ended December 31, 2021, as compared to the year ended December 31, 2020. The decrease is primarily a result of lower geological, geophysical, and seismic costs incurred in 2021 versus the prior period related to the U.S. Gulf of Mexico business unit and other exploration license areas sold to Shell in 2020. This decrease is partially offset by the Zora exploration well which did not find

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hydrocarbons and was plugged and abandoned in August 2021 with $14.6 million of well costs charged to exploration expense for the year ended December 31, 2021.

General and administrative. General and administrative costs increased by $19.4 million during the year ended December 31, 2021, as compared to the year ended December 31, 2020 primarily as a result of no employee or officers bonuses in 2020 as part of management’s response to COVID-19 offset by reduced employee compensation and general office expenses in 2021.

Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased $18.6 million during the year ended December 31, 2021, as compared with the year ended December 31, 2020 due to lower production volumes during 2021, partially offset by higher depletion rates during 2021 related to a reduction of proved reserves in the fourth quarter of 2020 largely tied to lower 2020 oil prices.

Impairment of long-lived assets. As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, we recorded asset impairments totaling $154.0 million during the year ended December 31, 2020 for oil and gas proved properties in the U.S. Gulf of Mexico. We did not recognize impairment of proved oil and gas properties during the year ended December 31, 2021 as no impairment indicators were identified.

Interest and other financing costs, net. Interest and other financing costs, net increased by $18.6 million during the year ended December 31, 2021, as compared to the year ended December 31, 2020 primarily a result of $19.6 million for loss on extinguishment of debt related to the Facility amendment and the Bridge Notes and a $26.9 million increase in interest expense from increased outstanding debt balance as a result of the issuance of the 7.750% Senior Notes and the 7.500% Senior Notes during 2021. These increases were partially offset by increased interest income on long-term notes receivables with the national oil companies of Mauritania and Senegal, as well as increased capitalized interest related to additional spend on the Greater Tortue Ahmeyim project during 2021.

Derivatives, net. During the years ended December 31, 2021 and 2020, we recorded a loss of $270.2 million and $17.2 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 $27.7 million from the prior year, primarily related to $16.4 million in restructuring charges for employee severance and related benefit costs as part of management’s response to COVID-19 and $11.2 million of asset impairments recorded in 2020.

Income tax expense (benefit). For the year ended 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. Additionally for December 31, 2020, our overall effective tax rate was impacted by a $30.9 million deferred tax expense related to valuation allowances on U.S. deferred tax assets recognized in a prior periods, and a $4.9 million tax benefit associated with the Coronavirus Aid, Relief and Economic Security ACT (“CARES ACT”).

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.

Current oil prices are volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. This volatility could result in wide fluctuations in future oil prices, which could impact our ability to comply with our financial covenants. To partially mitigate this price volatility, we maintain an active hedging program and review our capital spending program on a regular basis. Our investment decisions are based on longer-term commodity prices based on the nature of our projects and development plans. Current commodity prices, combined with our hedging program, and our current liquidity position support our capital program for 2022.

As such, our 2022 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 exploration, appraisal and development activities 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

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quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, the reliability of our oil and gas production facilities, our ability to continuously export oil and gas, our ability to secure and maintain partners and their alignment with respect to capital plans, the actual cost of exploitation, exploration, appraisal and development of our oil and natural gas assets, and coverage of any claims under our insurance policies.

In May 2021, in conjunction with the spring borrowing base redetermination, the Company agreed to an amendment and restatement of the Facility including a reduction in the facility size to $1.25 billion (from $1.5 billion), As amended, the Facility has an available borrowing base of $1.24 billion. During the September 2021 redetermination, the Company’s lending syndicate approved a borrowing base capacity of $1.25 billion. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields, however, excludes the additional interests in Jubilee and TEN acquired in the recent acquisition of Anadarko WCTP.

In September 2020, the Company entered into a five-year $200.0 million senior secured term-loan credit agreement secured against the Company's U.S. Gulf of Mexico assets with $175.0 million outstanding as of December 31, 2021.

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, 2021, 2020 and 2019:

Net cash provided by operating activities. Net cash provided by operating activities in 2021 was $374.3 million compared with net cash provided by operating activities of $196.1 million in 2020 and $628.2 million in 2019, respectively. 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 increased oil prices. The decrease in cash provided by operating activities in the year ended December 31, 2020 when compared to the same period in 2019 is primarily a result of lower production across our assets and lower oil prices stemming from the excess market supplies related to the COVID-19 pandemic.

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The following table presents our liquidity and financial position as of December 31, 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 infrastructure-led exploration and appraisal efforts in the U.S. Gulf of Mexico and Equatorial Guinea; and

•execute appraisal and development activities in Mauritania and Senegal.

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.

2022 Capital Program

We estimate we will spend approximately $700 million of capital for the year ending December 31, 2022. 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 $100-$150 million related to growth activities across our Ghana, Equatorial Guinea and U.S. Gulf of Mexico assets, primarily pre-investment for infrastructure required to support production growth in 2023 and beyond

•Approximately $250 million related to development of Phase 1 of GTA, net of FPSO transaction benefit

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•Approximately $50 million related to progressing the appraisal plans of our greater gas resource in Mauritania and Senegal, including Phase 2 of GTA, BirAllah and Yakaar-Teranga.

Our estimated capital spend may be reduced by up to $40 million, depending on timing, if the pre-emption of our acquisition of additional interests in Ghana discussed in “Item 8. Financial Statements and Supplementary Data—Note 3—Acquisitions and Divestitures” is completed. 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 with a borrowing base calculation that includes value related to the Jubilee, TEN, Ceiba and Okume fields, however, the additional interests in Jubilee and TEN acquired in the recent acquisition of Anadarko WCTP are not included in the borrowing base calculation. In May 2021, the Company entered into an amended and restated facility agreement and certain ancillary documents. As amended, the available borrowing base was approximately $1.24 billion. During the September 2021 redetermination, the Company’s lending syndicate approved a borrowing base capacity in excess of the facility size of $1.25 billion. As of December 31, 2021, borrowings under the Facility totaled $1.0 billion and the undrawn availability under the Facility was $235.2 million, (limited by current commitments).

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, 2021, 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. 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 Ghana and Equatorial Guinea, however, excludes the additional interests in Jubilee and TEN acquired in the recent acquisition of Anadarko WCTP.

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, 2021 (the most recent assessment date). The Facility contains customary cross default provisions.

Corporate Revolver

In August 2018, we amended and restated the Corporate Revolver maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5%. This results in lower commitment fees on the undrawn portion of the total commitments, which is 30% per annum of the respective margin. The Corporate Revolver is available for general corporate purposes and for oil and gas exploration, appraisal and development programs. As of December 31, 2021, there were no outstanding borrowings under the Corporate Revolver and the undrawn availability under the Corporate Revolver was $400.0 million.

The Corporate Revolver expires on May 31, 2022. 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.

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We were in compliance with the financial covenants contained in the Corporate Revolver as of September 30, 2021 (the most recent assessment date). The Corporate Revolver contains customary cross default provisions. We intend to refinance the Corporate Revolver in the first quarter of 2022.

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.

7.125% Senior Notes due 2026

In April 2019, the Company issued $650.0 million of 7.125% Senior Notes and received net proceeds of approximately $640.0 million after deducting commissions and other expenses. We used the net proceeds to redeem all of the Senior Secured Notes, repay a portion of the outstanding indebtedness under the Corporate Revolver and pay fees and expenses related to the redemption, repayment and the issuance of the Senior Notes. See Note 8 of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data."

The 7.125% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company’s subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the 7.125% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. The 7.125% Senior Notes contain customary cross default provisions.

7.750% Senior Notes due 2027

In October 2021, the Company issued $400.0 million of 7.750% Senior Notes and received net proceeds of approximately $395.0 million after deducting fees. We used the net proceeds, together with cash on hand, to refinance the Bridge Notes and to pay expenses related to the issuance of the 7.750% Senior Notes.

The 7.750% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the 7.750% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred and is continuing. The 7.750% Senior Notes contain customary cross default provisions.

7.500% Senior Notes due 2028

In March 2021, the Company issued $450.0 million of 7.500% Senior Notes and received net proceeds of approximately $444.4 million after deducting fees. We used the net proceeds to repay outstanding indebtedness under the Corporate Revolver and the Facility, to pay expenses related to the issuance of the 7.500% Senior Notes and for general corporate purposes.

The 7.500% Senior Notes indenture restricts the ability of the Company and its restricted subsidiaries to, among other things: incur or guarantee additional indebtedness, create liens, pay dividends or make distributions in respect of capital stock, purchase or redeem capital stock, make investments or certain other restricted payments, sell assets, enter into agreements that restrict the ability of the Company's subsidiaries to make dividends or other payments to the Company, enter into transactions with affiliates, or effect certain consolidations, mergers or amalgamations. These covenants are subject to a number of important qualifications and exceptions. Certain of these covenants will be terminated if the 7.500% Senior Notes are assigned an investment grade rating by both Standard & Poor’s Rating Services and Fitch Ratings Inc. and no default or event of default has occurred. The 7.500% Senior Notes contain customary cross default provisions.

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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, 2021, borrowings under the GoM Term Loan totaled $175 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.

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, 2021. 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)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

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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 one exploration well in Mauritania and 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 company’s share of certain development costs. Kosmos’ total share for the two agreements combined is currently estimated at approximately $240.0 million, of which $145.2 million has been incurred through December 31, 2021. These amounts will be repaid through the national oil companies’ share of future revenues.

Critical Accounting Policies

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

Revenue Recognition. We recognize revenues on the volumes of hydrocarbons sold to a purchaser. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of December 31, 2021 and 2020, 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, 2021 and 2020,

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we have a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. If our estimates and judgments regarding our ability to realize our deferred tax assets change, the benefits associated with those deferred tax assets may increase or decrease in the period our estimates and judgments change. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

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

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

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

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

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

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

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

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

•the engineering and geological interpretation of available data;

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

•the accuracy of various mandated economic assumptions; and

•the judgments of the persons preparing the estimates.

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

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

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

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

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

New Accounting Pronouncements

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