KOSMOS ENERGY LTD. The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year endedDecember 31, 2020 , included in our annual report on Form 10-K along with the section Management's Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with "Risk Factors" under Item 1A of this report and in the annual report, along with "Forward-Looking Information" at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are a full-cycle deepwater independent oil and gas exploration and production company focused along the Atlantic Margins. Our key assets include production offshoreGhana ,Equatorial Guinea andU.S. Gulf of Mexico , as well as a world-class gas development offshoreMauritania andSenegal . We also maintain a sustainable proven basin exploration program inEquatorial Guinea ,Ghana andU.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 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. Recent Developments Corporate
During the third quarter of 2021, Kosmos received the remaining proceeds of
InOctober 2021 , Kosmos completed the acquisition ofAnadarko WCTP Company ("Anadarko WCTP"), a subsidiary of Occidental Petroleum Corporation, which owns a participating interest in the WCTP Block and DT Block offshoreGhana , 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 approximately$460.0 million in cash based on an initial purchase price of$550.6 million reduced by certain purchase price adjustments totaling$94.7 million . 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%. Kosmos initially funded the purchase price through the issuance of$400.0 million aggregate principal amount of floating rate senior notes due 2022 (the "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 plans to use the proceeds to repay outstanding borrowings under the Facility during the fourth quarter of 2021. 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%. This pre-emption right exists untilNovember 12, 2021 .Ghana During the third quarter of 2021,Ghana production averaged approximately 108,200 Bopd gross (22,700 Bopd net). Jubilee production averaged approximately 77,800 Bopd gross (17,800 Bopd net) with consistent water injection and gas offtake and TEN production averaged approximately 30,400 Bopd gross (4,900 Bopd net). In the third quarter of 2021, the multi-year development drilling program continued to progress, with the successful completion of one producer and one water injector well in the Jubilee Field. The first Jubilee producer well (J-56P) started production inJuly 2021 and the Jubilee injector 33 -------------------------------------------------------------------------------- Table of Contents well (J-55W) came online inSeptember 2021 . InOctober 2021 , the TEN gas injector well (NT-06G) was successfully completed and brought online. The rig then moved to drill and complete the second Jubilee producer well (J57-P), which is expected online around year-end.
Production from theU.S. Gulf of Mexico averaged approximately 17,000 Boepd net (~81% oil) for the third quarter of 2021. The impact of the unplanned downtime from hurricanes to production in theU.S. Gulf of Mexico was approximately 4,000 barrels of oil equivalent per day in the third quarter or 1,000 barrels of oil equivalent to the full year compared to our previous production forecasts for 2021. Production has now returned to around pre-hurricane levels. InApril 2021 , the Kodiak #3 infill well located in MississippiCanyon 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 has been shut-in. We are currently working with our partners to evaluate the best options to enhance production from the Kodiak field. During the second quarter of 2021, the Tornado-5 infill well located in the GreenCanyon Block 281 (35.0% working interest) was successfully drilled and completed. The Tornado-5 well was brought online inJuly 2021 and is performing at the top end of expectations. InJanuary 2021 , we announced the Winterfell exploration well encountered approximately 26 meters (85 feet) of net oil pay in two intervals. Winterfell was designed to test a sub-salt Upper Miocene prospect located inGreen Canyon Block 944. InSeptember 2021 , we spudded an appraisal well to the Winterfell discovery in GreenCanyon Block 943, with results expected in the fourth quarter of 2021. The appraisal well is planned to evaluate the adjacent fault block to the northwest of the original discovery, which has the same seismic signature as the Winterfell exploration well, with an exploration tail into a deeper horizon. The results of the appraisal well will also help refine development options for the discovery. InJuly 2021 , the Company commenced drilling the Zora infrastructure-led exploration prospect located inDeSoto Canyon Block 266 (37.5% working interest). The well did not find hydrocarbons and was plugged and abandoned inAugust 2021 . The well results will be integrated into the ongoing evaluation of the surrounding area. The Company recorded approximately$14.1 million of exploration expense for the nine months endedSeptember 30, 2021 related to the well.Equatorial Guinea Production inEquatorial Guinea averaged approximately 29,900 Bopd gross (9,600 Bopd net) in the third quarter of 2021. InApril 2021 ,one ESP conversion was completed with two additional ESP conversions planned to be completed in 2022. The first of three planned infill wells in theOkume Complex was completed inAugust 2021 with hookup currently in progress. In the third quarter of 2021, the operator commenced drilling the an additional well, which is expected to be online in the fourth quarter of 2021. The third planned well is now expected to be deferred, as the rig is being utilized to plug and abandon an existing well inEquatorial Guinea and is required to mobilize for its' next contract before it can complete the drilling of the last well.
During the first quarter of 2021, BP, as the operator of the Cayar block offshoreSenegal , provided notice to the Government ofSenegal 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 discovery at Yakaar Teranga. OnJuly 5, 2021 a presidential decree was issued extending the term of the license for up to an additional three years.
Greater Tortue Ahmeyim Unit
Phase 1 of the Greater Tortue project continues to make steady progress in 2021 with first gas for the project expected in the third quarter of 2023. The following milestones were achieved as of the end of the third quarter of 2021 and post quarter-end:
•FLNG: Mechanical completion activities have commenced with instrument loop checks
•FPSO: Topsides integration and hull and living quarters mechanical completion activities have commenced
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•Breakwater: Commenced fabrication of 20th caisson (of 21) with 12 installed
•Subsea:
InAugust 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 inChina ) to an affiliate of BP ("BP Buyer "). The Greater Tortue FPSO will be leased back toBP 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 toBP Buyer will occur after construction is complete and the Greater Tortue FPSO has been commissioned, with the lease toBP 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 byBP Operator , Kosmos has recognized a Long-term receivable of$200.2 million fromBP Operator for our share of the consideration paid fromBP Buyer to and held byBP 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 toBP Operator . During the third quarter of 2021,BP Operator settled our payment obligations of$51.2 million of capital expenditures and$42.7 million of existing Accounts Payable toBP Operator . 35 -------------------------------------------------------------------------------- Table of Contents Results of Operations All of our results, as presented in the table below, represent operations from Jubilee and TEN fields inGhana , theU.S. Gulf of Mexico andEquatorial Guinea . Certain operating results and statistics for the three and nine months endedSeptember 30, 2021 and 2020 are included in the following tables: Three Months Ended September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (In thousands, except per volume data) Sales volumes: Oil (MBbl) 2,719 5,160 11,349 14,361 Gas (MMcf) 1,078 1,167 3,624 4,451 NGL (MBbl) 111 122 365 457 Total (MBoe) 3,010 5,477 12,318 15,560 Total (Boepd) 32,714 59,527 45,121 56,788 Revenues: Oil sales$ 190,599 $ 220,653 $ 737,381 $ 517,382 Gas sales 4,508 2,314 12,727 8,146 NGL sales 3,829 1,819 9,347 4,352 Total revenues$ 198,936 $ 224,786 $ 759,455 $ 529,880 Average oil sales price per Bbl$ 70.10 $ 42.76 $ 64.97$ 36.03 Average gas sales price per Mcf 4.18 1.98 3.51 1.83 Average NGL sales price per Bbl 34.50 14.91 25.61 9.52 Average total sales price per Boe 66.10 41.05 61.65 34.05
Costs:
Oil and gas production, excluding workovers
$ 201,975 $ 233,141 Oil and gas production, workovers 3,134 (3,721) 9,896 1,486
Total oil and gas production costs
Depletion, depreciation and amortization
Average cost per Boe: Oil and gas production, excluding workovers$ 15.68 $ 16.07 $ 16.40$ 14.98 Oil and gas production, workovers 1.04 (0.68) 0.80 0.10 Total oil and gas production costs 16.72 15.39 17.20 15.08 Depletion, depreciation and amortization 21.57 20.31 23.76 20.98 Total$ 38.29 $ 35.70 $ 40.96$ 36.06 36
-------------------------------------------------------------------------------- Table of Contents The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as ofSeptember 30, 2021 : Actively Drilling or Wells Suspended or Completing Waiting on Completion Exploration Development Exploration Development Gross Net Gross Net Gross Net Gross NetGhana Jubilee Unit - - - - - - 9 2.17 TEN - - 1 0.17 - - 5 0.85 Equatorial Guinea Block S - - - - 1 0.40 - - Okume - - 1 0.43 - - 1 0.43 U.S. Gulf of Mexico Winterfell 1 0.16 - - 1 0.18 - - Mauritania / Senegal Mauritania C8 - - - - 2 0.56 - - Greater Tortue Ahmeyim Unit - - - - 3 0.80 1 0.27 Senegal Cayar Profond - - - - 3 0.90 - - Total 1 0.16 2 0.60 10 2.84 16 3.72 37
-------------------------------------------------------------------------------- Table of Contents 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. Three months endedSeptember 30, 2021 compared to three months endedSeptember 30, 2020 Three Months Ended September 30, Increase 2021 2020 (Decrease) (In thousands) Revenues and other income: Oil and gas revenue$ 198,936 $ 224,786 $ (25,850) Gain on sale of assets 1,538 - 1,538 Other income, net 66 1 65 Total revenues and other income 200,540 224,787
(24,247)
Costs and expenses: Oil and gas production 50,316 84,277
(33,961)
Facilities insurance modifications, net 1,554 2,465
(911) Exploration expenses 23,982 13,977 10,005 General and administrative 22,459 18,269 4,190
Depletion, depreciation and amortization 64,914 111,231 (46,317)
Interest and other financing costs, net 26,873 27,068
(195) Derivatives, net 38,224 1,187 37,037 Other expenses, net 194 2,805 (2,611) Total costs and expenses 228,516 261,279 (32,763) Loss before income taxes (27,976) (36,492) 8,516 Income tax expense 621 892 (271) Net loss$ (28,597) $ (37,384) $ 8,787 Oil and gas revenue. Oil and gas revenue decreased by$25.9 million as a result of lower sales volumes due to cargo timing in our international operations partially offset by higher oil prices. We sold 3,010 MBoe at an average realized price per barrel equivalent of$66.10 during the three months endedSeptember 30, 2021 and 5,477 MBoe at an average realized price per barrel equivalent of$41.05 during the three months endedSeptember 30, 2020 . Oil and gas production. Oil and gas production costs decreased by$34.0 million during the three months endedSeptember 30, 2021 , as compared to the three months endedSeptember 30, 2020 primarily as a result of lower sales volumes in the current quarter offset by increased workover costs and higher production costs per barrel from the field production mix in theU.S. Gulf of Mexico . General and administrative. General and administrative costs increased by$4.2 million during the three months endedSeptember 30, 2021 , as compared with the three months endedSeptember 30, 2020 primarily as a result of not accruing employee bonuses in 2020 as part of management's response to COVID-19. Exploration expenses. Exploration expenses increased by$10.0 million during the three months endedSeptember 30, 2021 , as compared to the three months endedSeptember 30, 2020 primarily as result of the Zora exploration well. The well did not find hydrocarbons and was plugged and abandoned inAugust 2021 with$12.6 million of well costs charged to exploration expense for the three months endedSeptember 30, 2021 . Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased$46.3 million during the three months endedSeptember 30, 2021 , as compared with the three months endedSeptember 30, 2020 primarily as a result of lower sales volumes during the current quarter. 38 -------------------------------------------------------------------------------- Table of Contents Derivatives, net. During the three months endedSeptember 30, 2021 and 2020, we recorded a loss of$38.2 million and a loss of$1.2 million , respectively, on our outstanding hedge positions. The amounts recorded were a result of changes in the forward oil price curve during the respective periods. Income tax expense (benefit). For the three months endedSeptember 30, 2021 and 2020, our overall effective tax rates were impacted by the difference in our 21%U.S. income tax reporting rate and the 35% statutory tax rates applicable to our Ghanaian and Equatorial Guinean operations, jurisdictions that have a 0% statutory tax rate or where we have incurred losses and have recorded valuation allowances against the corresponding deferred tax assets, and other non-deductible expenses, primarily in theU.S. Nine months endedSeptember 30, 2021 compared to nine months endedSeptember 30, 2020 Nine Months Ended September 30, Increase 2021 2020 (Decrease) (In thousands) Revenues and other income: Oil and gas revenue$ 759,455 $ 529,880 $ 229,575 Gain on sale of assets 1,564 - 1,564 Other income, net 210 2 208 Total revenues and other income 761,229 529,882
231,347
Costs and expenses: Oil and gas production 211,871 234,627
(22,756)
Facilities insurance modifications, net 3,495 10,555
(7,060) Exploration expenses 41,452 74,293 (32,841) General and administrative 66,628 57,366 9,262
Depletion, depreciation and amortization 292,616 326,390
(33,774)
Impairment of long-lived assets - 150,820
(150,820)
Interest and other financing costs, net 90,727 83,177
7,550
Derivatives, net 252,606 (34,776) 287,382
Other expenses, net 1,003 27,962 (26,959)
Total costs and expenses 960,398 930,414 29,984
Loss before income taxes (199,169) (400,532) 201,363
Income tax expense (22,617) 19,010 (41,627)
Net loss $ (176,552) $ (419,542) $ 242,990
Oil and gas revenue. Oil and gas revenue increased by $229.6 million as a
result of higher oil prices partially offset by lower sales volumes due to lower
production rates resulting in fewer scheduled liftings from our international
operations. We sold 12,318 MBoe at an average realized price per barrel
equivalent of $61.65 during the nine months ended September 30, 2021 and 15,560
MBoe at an average realized price per barrel equivalent of $34.05 during the
nine months ended September 30, 2020 .
Oil and gas production. Oil and gas production costs decreased by $22.8
million during the nine months ended September 30, 2021 , as compared to the nine
months ended September 30, 2020 primarily as a result of lower sales and
production volumes in the current year (including TEN fields offshore Ghana )
offset by higher production costs per barrel from the field production mix in
the U.S. Gulf of Mexico .
Facilities insurance modifications, net. During the nine months ended
Exploration expenses. Exploration expenses decreased by$32.8 million during the nine months endedSeptember 30, 2021 , as compared to the nine months endedSeptember 30, 2020 . The decrease is primarily a result of lower geological, geophysical, and seismic costs incurred in 2021 versus the prior period related to theU.S. Gulf of Mexico business unit and 39 -------------------------------------------------------------------------------- Table of Contents other exploration license areas sold to Shell in 2020. This decrease is partially offset by the Zora exploration well which did not find hydrocarbons and was plugged and abandoned inAugust 2021 with$14.1 million of well costs charged to exploration expense for the nine months endedSeptember 30, 2021 . General and administrative. General and administrative costs increased by$9.3 million during the nine months endedSeptember 30, 2021 , as compared with the nine months endedSeptember 30, 2020 primarily as a result of not accruing employee bonuses in 2020 as part of management's response to COVID-19 offset by reduced expenditures on general office costs. Depletion, depreciation and amortization. Depletion, depreciation and amortization decreased$33.8 million during the nine months endedSeptember 30, 2021 , as compared with the nine months endedSeptember 30, 2020 primarily as a result of lower sales volumes in the current year partially offset by higher depletion rates from a reduction of proved reserves in the fourth quarter of 2020 and field production mix. 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$150.8 million during the nine months endedSeptember 30, 2020 for oil and gas proved properties in theU.S. Gulf of Mexico . We did not recognize impairment of proved oil and gas properties during the nine months endedSeptember 30, 2021 as no impairment indicators were identified. Interest and other financing costs, net. Interest and other financing costs, net increased$7.6 million primarily a result of$15.2 million for loss on extinguishment of debt during the second quarter of 2021 related to the Facility amendment offset by increased interest income on long-term receivable balances from GNPC inGhana and the national oil companies inMauritania andSenegal during the nine months endedSeptember 30, 2021 , as compared to the nine months endedSeptember 30, 2020 . Derivatives, net. During the nine months endedSeptember 30, 2021 and 2020, we recorded a loss of$252.6 million and a gain of$34.8 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$27.0 million during the nine months endedSeptember 30, 2021 , as compared with the nine months endedSeptember 30, 2020 primarily related to$13.3 million in restructuring charges for employee severance and related benefit costs and$5.7 million of asset impairments recorded in 2020. In addition, we received$8.1 million of insurance recoveries in 2021. Income tax expense (benefit). For the nine months endedSeptember 30, 2021 and 2020, 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 theU.S. Additionally forSeptember 30, 2020 , our overall effective tax rate was impacted by a$30.9 million deferred tax expense related to valuation allowances onU.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,
partner carries and our current liquidity position support our remaining capital
program for 2021.
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Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash
equivalents and restricted cash for the nine months ended September 30, 2021 and
2020:
Nine Months Ended
September 30,
2021 2020
(In thousands)Sources of cash, cash equivalents and restricted cash: Net cash provided by operating activities
$ 143,841 $
20,657
Net proceeds from issuance of senior notes 444,375
-
Borrowings under long-term debt 250,000
300,000
Advances under production prepayment agreement - 50,000
Proceeds on sale of assets 5,327 1,713
843,543 372,370
Uses of cash, cash equivalents and restricted cash:
Oil and gas assets 377,125 215,425
Other property 725 1,838
Notes receivable from partners 41,712 53,574
Payments on long-term debt 400,000 -
Purchase of treasury stock 1,100 4,947
Dividends 512 19,174
Deferred financing costs 17,291 4,570
838,465 299,528
Increase in cash, cash equivalents and restricted cash
Net cash provided by operating activities. Net cash provided by operating
activities for the nine months ended
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The following table presents our net debt and liquidity as ofSeptember 30, 2021 : September 30, 2021 (In thousands) Cash and cash equivalents$ 111,329 Restricted cash 43,513 7.125% Senior Notes 650,000 7.500% Senior Notes 450,000 Borrowings under the Facility 1,150,000 Borrowings under the Corporate Revolver - Borrowings under the GoM Term Loan 200,000 Net debt$ 2,295,158 Availability under the Facility$ 85,155 Availability under the Corporate Revolver$ 400,000
Available borrowings plus cash and cash equivalents
Capital Expenditures and Investments
We expect to incur capital costs as we:
• drill additional wells and execute exploitation activities in
• execute infrastructure-led exploration and appraisal efforts in the
• execute exploration, appraisal and development activities in
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 thirdparty 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. 2021 Capital Program We estimate we will spend around$300 million of capital, which includes the additional acquired interests inGhana and excludes amounts related toMauritania andSenegal , in our base business for the year endingDecember 31, 2021 . ThroughSeptember 30, 2021 , we have spent approximately$184.3 million on base business capital expenditures. Capital expenditures associated with the Greater Tortue project in 2021 net to Kosmos was previously estimated to be around$350 million . With the completion of the Greater Tortue FPSO sale transaction inAugust 2021 , our 2021 capital expenditures associated with the Greater Tortue project have been reduced to around$180 million , with the remaining cash calls on the Greater Tortue project for 2021 covered through the proceeds of the sale. The balance of the sale proceeds, as well as the additional savings from the transfer of the remaining FPSO construction payments toBP Buyer , are expected to be largely realized in 2022. ThroughSeptember 30, 2021 , we have spent approximately$169.2 million of capital expenditures related toMauritania andSenegal . 42 -------------------------------------------------------------------------------- Table of Contents In relation to the additional capital expenditures associated with the additional acquired interests inGhana , certain joint venture partners have pre-emption rights under the Deepwater Tano Block Joint Operating Agreement 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%. This pre-emption right exists untilNovember 12, 2021 and, if exercised, will reduce our capital expenditures associated with the additional acquired interests. 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. As ofSeptember 30, 2021 , borrowings under the Facility totaled$1.15 billion and the undrawn availability under the facility was$85.2 million (limited by current commitments). InMay 2021 , the Company entered into an amended and restated facility agreement and certain ancillary documents. The amendments to the terms of the Facility included the following:
•the extension of the maturity date by two years (final maturity date now occurs
on
•the extension of the amortization schedule such that amortization of principal is to commence onMarch 31, 2024 and continue in equal amounts every six months thereafter until the maturity date,
•an increase in the interest margin by 0.5% (applicable interest margin for the first three years is now LIBOR +3.75%),
•the incorporation of a mechanism for two ESG key performance indicators ("KPIs") to impact the interest margin either positively or negatively based upon delivering emissions targets and achieving certain third party ESG ratings,
•an increase in the Loan Life Coverage Ratio from 1.10x to 1.30x after
•the removal ofKosmos Energy Investments Senegal Limited , Kosmos Energy Senegal and Kosmos Energy Mauritania as borrowers, guarantors and pledged subsidiaries, and
•a reduction in the Facility size to
As amended, the Facility has an available borrowing base of approximately$1.24 billion . As part of the amendment, the Company incurred$15.2 million for loss on extinguishment of debt during the second quarter of 2021. During theSeptember 2021 redetermination, the Company's lending syndicate approved a borrowing base capacity in excess of the facility size of$1.25 billion . When our net leverage ratio exceeds 2.50x, we are required under the Facility to maintain a restricted cash balance that is sufficient to meet the payment of interest and fees for the next six-month period on the 7.125% Senior Notes and the 7.500% Senior Notes plus the Corporate Revolver or the Facility, whichever is greater. As ofSeptember 30, 2021 we have restricted cash of approximately$42.9 million to meet our requirements. As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, inJuly 2020 , we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation throughDecember 31, 2021 . The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. We were in compliance with the financial covenants as of the most recent assessment date. The Facility, as amended, contains customary cross default provisions. 43 -------------------------------------------------------------------------------- Table of Contents Corporate Revolver InAugust 2018 , we amended and restated the Corporate Revolver maintaining the borrowing capacity at$400.0 million , extending the maturity date fromNovember 2018 toMay 2022 and lowering the margin 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 ofSeptember 30, 2021 , there were no outstanding borrowings under the Corporate Revolver and the undrawn availability was$400.0 million . As a result of the impact of COVID-19 on the demand for oil and the related significant decrease in oil prices, our ability to comply with one of our financial covenants, the debt cover ratio, may be impacted in future periods. Therefore, inJuly 2020 , we proactively worked with our lender group, prior to any inability to comply with the financial covenants thereunder, to amend the debt cover ratio calculation throughDecember 31, 2021 . The amendment makes this covenant less restrictive during the stated period up to a maximum of 4.75x and thereafter gradually returns to the originally agreed upon ratio of 3.5x. We were in compliance with the financial covenants as of the most recent assessment date. The Corporate Revolver contains customary cross default provisions.
7.125% Senior Notes due 2026
InApril 2019 , the Company issued$650.0 million of 7.125% Senior Notes and received net proceeds of approximately$640.0 million after deducting fees and other expenses. We used the net proceeds to redeem all of the previously issued 7.875% Senior Secured Notes due 2021, 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 7.125% Senior Notes. The 7.125% Senior Notes mature onApril 4, 2026 . Interest is payable in arrears eachApril 4 andOctober 4 , commencing onOctober 4, 2019 . The 7.125% Senior Notes are senior, unsecured obligations ofKosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver and the 7.500% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.125% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company'sU.S. Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that guarantee the Facility. We were in compliance with the financial covenants contained in the 7.125% Senior Notes as ofSeptember 30, 2021 . The 7.125% Senior Notes contain customary cross default provisions.
7.500% Senior Notes due 2028
InMarch 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 mature onMarch 1, 2028 . Interest is payable in arrears eachMarch 1 andSeptember 1 , commencing onSeptember 1, 2021 . The 7.500% Senior Notes are senior, unsecured obligations ofKosmos Energy Ltd. and rank equal in right of payment with all of its existing and future senior indebtedness (including all borrowings under the Corporate Revolver and the 7.125% Senior Notes) and rank effectively junior in right of payment to all of its existing and future secured indebtedness (including all borrowings under the Facility) and all borrowings under the GoM Term Loan. The 7.500% Senior Notes are guaranteed on a senior, unsecured basis by certain subsidiaries owning the Company'sU.S. Gulf of Mexico assets, and on a subordinated, unsecured basis by certain subsidiaries that borrow under, or guarantee, the Facility and, on a subordinated basis, guarantee the Corporate Revolver and the 7.125% Senior Notes. 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. Certain of these covenants will be terminated if the 7.500% Senior Notes are assigned an investment grade rating by bothStandard & Poor's Rating Services andFitch Ratings Inc. and no default or event of default has occurred. We were in compliance with the financial covenants contained in the 7.500% Senior Notes as ofSeptember 30, 2021 . The 7.500% Senior Notes contain customary cross default provisions. 44 -------------------------------------------------------------------------------- Table of Contents Production Prepayment Agreement InJune 2020 , the Company received$50.0 million from Trafigura under a Production Prepayment Agreement of crude oil sales related to a portion of ourU.S. Gulf of Mexico production primarily in 2022 and 2023. The Company terminated the Production Prepayment Agreement and the initial prepayment of$50.0 million advanced under the Production Prepayment Agreement by Trafigura in the second quarter of 2020 was extinguished and converted into the GoM Term Loan as ofSeptember 30, 2020 . GoM Term Loan InSeptember 2020 , the Company entered into a five-year$200.0 million senior secured term-loan credit agreement secured against the Company'sU.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$100.0 million subject to certain conditions. The GoM Term Loan bears interest at an effective rate of approximately 6% per annum and matures in 2025, with principal repayments beginning in the fourth quarter of 2021. We were in compliance with the covenants, representations and warranties contained in the GoM Term Loan as of as ofSeptember 30, 2021 (the most recent assessment date). The GoM Term Loan contains customary cross default provisions.
Contractual Obligations
The following table summarizes by period the payments due for our estimated contractual obligations as ofSeptember 30, 2021 and 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 include amortization of deferred financing costs. Asset (Liability) Fair Value at Years Ending December 31, September 30, 2021(2) 2022 2023 2024 2025 Thereafter Total 2021 (In thousands, except percentages) Fixed rate debt: 7.125% Senior Notes $ - $ - $
- $ - $ -
- - - - - 450,000 450,000 (436,905)
Variable rate debt:
Weighted average interest rate
on variable rate debt 4.22 % 4.26 % 4.63 % 5.36 % 5.77 % 6.38 %
Facility(1) $ - $ - $ 112,621 $ 207,834 $ 300,192 $ 529,353 $ 1,150,000 $ (1,150,000)
GoM Term Loan 7,500 30,000 30,000 30,000 102,500 - 200,000 (200,000)
Total principal debt repayments(1)$ 7,500 $ 30,000 $ 142,621 $ 237,834 $ 402,692 $ 1,629,353 $ 2,450,000 Interest & commitment fee payments on long-term debt 39,498 140,981 140,117 138,484 124,287 133,143 716,510 Operating leases 426 3,932 4,075 4,146 4,217 15,161 31,957
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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 ofSeptember 30, 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)Represents the periodOctober 1, 2021 throughDecember 31, 2021 . 45 -------------------------------------------------------------------------------- Table of Contents The table above does not include 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 14 - Additional Financial Information for additional information regarding these liabilities. We currently have a commitment to drill one exploration well inMauritania and a$200.2 million FPSO Contract Liability related to the deferred sale of the Greater Tortue FPSO.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As ofSeptember 30, 2021 , our off-balance sheet arrangements and transactions include short-term operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos' liquidity or availability of or requirements for capital resources.
Critical Accounting Policies
We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and natural gas reserves, asset retirement obligations, leases and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. Other than items discussed in Note 2 - Accounting Policies, there have been no changes to our critical accounting policies which are summarized in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" section in our annual report on Form 10-K, for the year endedDecember 31, 2020 .
Cautionary Note Regarding Forward-looking Statements
This quarterly report on Form 10-Q contains estimates and forward-looking statements, principally in "Management's Discussion and Analysis of Financial Condition and Results of Operations." Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our quarterly report on Form 10-Q and our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this quarterly report on Form 10-Q, the annual report on Form 10-K and the documents that we have filed with theSecurities and Exchange Commission completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward-looking statements may be influenced by the following factors, among others: •the impact of the COVID-19 pandemic on the Company and the overall business environment; •our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects; •uncertainties inherent in making estimates of our oil and natural gas data; •the successful implementation of our and our block partners' prospect discovery and development and drilling plans; •projected and targeted capital expenditures and other costs, commitments and revenues; •termination of or intervention in concessions, rights or authorizations granted to us by the governments of the countries in which we operate (or their respective national oil companies) or any other federal, state or local governments or authorities; •our dependence on our key management personnel and our ability to attract and retain qualified technical personnel; •the ability to obtain financing and to comply with the terms under which such financing may be available; •the volatility of oil, natural gas and NGL prices, as well as our ability to implement hedges addressing such volatility on commercially reasonable terms; •the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects; •the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services; 46
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Table of Contents •other competitive pressures; •potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards; •current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes; •cost of compliance with laws and regulations; •changes in, or new, environmental, health and safety or climate change or GHG laws, regulations and executive orders, or the implementation, or interpretation, of those laws, regulations and executive orders; •adverse effects of sovereign boundary disputes in the jurisdictions in which we operate; •environmental liabilities; •geological, geophysical and other technical and operations problems, including drilling and oil and gas production and processing; •military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes; •the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements; •our vulnerability to severe weather events, including tropical storms and hurricanes in theGulf of Mexico ; •our ability to meet our obligations under the agreements governing our indebtedness; •the availability and cost of financing and refinancing our indebtedness; •the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit, performance bonds and other secured debt; •the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in; •our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and •other risk factors discussed in the "Item 1A. Risk Factors" section of our quarterly reports on Form 10-Q and our annual report on Form 10-K. The words "believe," "may," "will," "aim," "estimate," "continue," "anticipate," "intend," "expect," "plan" and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this quarterly report on Form 10-Q might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.
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