Kosmos Energy Ltd. - Annual Report: 2019 (Form 10-K)

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•	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;

•	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;

•	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 environmental, health and safety or climate change or GHG laws and regulations or the implementation, or interpretation, of those laws and regulations;

•	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;

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•	our vulnerability to severe weather events, including tropical storms and hurricanes in the Gulf 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 this annual report on Form 10‑K.

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(1)	For information concerning our estimated proved reserves as of December 31, 2019, see “—Our Reserves.”

(2)	The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.

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(1)	For information concerning our estimated proved reserves as of December 31, 2019, see “—Our Reserves.”

(2)

The Jubilee Field straddles the boundary between the WCTP petroleum contract and the DT petroleum contract offshore Ghana. To optimize resource recovery in this field, we entered into the Jubilee UUOA in July 2009 with the GNPC and the other block partners of each of these two blocks. The Jubilee UUOA governs the interests in and development of the Jubilee Field and created the Jubilee Unit from portions of the WCTP petroleum contract and the DT petroleum contract areas.

(3)

The Greater Tortue Ahmeyim Unit, which includes the Ahmeyim discovery in Mauritania Block C8 and the Guembeul discovery in the Senegal Saint Louis Offshore Profond Block, straddles the border between Mauritania and Senegal. To optimize resource recovery in this field, we entered into the GTA UUOA in February 2019 with the governments of Mauritania and Senegal. The GTA UUOA governs interests in and development of the Greater Tortue Ahmeyim Field and created the Greater Tortue Ahmeyim Unit from portions of the Mauritania Block C8 and the Senegal Saint Louis Offshore Profond Block areas.

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(4)	Our paying interest on development activities in the TEN fields is 19%.

(5)	Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.

(6)	SMHPM has the option to acquire up to an additional 4% participating interest in a commercial development on Block C8. These interest percentages do not give effect to the exercise of such option.

(7)	PETROSEN has the option to acquire up to an additional 10% participating interest in a commercial development on the Saint Louis Offshore Profond and Cayar Offshore Profond Blocks. The interest percentage does not give effect to the exercise of such option.

(8)	Our U.S. Gulf of Mexico blocks are held by production/operations, and the lease periods extend as long as production/governmental approved operations continue on the relevant block.

(9)	License expiration date can be extended by an additional ten years subject to certain conditions being met.

(10)	License expiration date can be extended by an additional twenty years subject to certain conditions being met.

(1)	PETROCI has the option to acquire up to an additional 2% paying interests in a commercial development. The interest percentage does not give effect to the exercise of such option.

(2)	Should a commercial discovery be made, GEPetrol's 20% carried interest will convert to a 20% participating interest for all development and production operations.

(3)

Should a commercial discovery be made, SMHPM’s 10% carried interest is extinguished and SMHPM will have an option to obtain a participating interest in the discovery area between 10% and 14% (blocks C8, C12 and C13) and 10% and 18% (Block C6). SMHPM will pay its portion of development and production costs in a commercial development on the blocks. The interest percentage does not give effect to the exercise of such option.

(4)	Should a commercial discovery be made, NAMCOR's 10% carried interest during the exploration period may continue through first commercial production but must be reimbursed through production.

(5)	ANP-STP's carried interest may be converted to a full participating interest at any time. ANP-STP will reimburse any costs, expenses and any amount incurred on its behalf prior to the election. Formal withdraw notice on STP Block 12 was communicated to partners on December 13, 2019 and was effective January 31, 2020.

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(6)	PETROSEN has the option to obtain up to an additional 10% paying interest in a commercial development on the Saint Louis Offshore Profond and Cayar Offshore Profond Blocks. The interest percentage does not give effect to the exercise of such option.

(7)	The Republic of South Africa has the option to obtain a percentage of the participating interest ("State Option") in accordance with the provisions of the Applicable Laws prevailing at the time of the granting of a Production Right governing State Option requirements.

(8)	Should a commercial discovery be made, Staatsolie has the option to participate up to 10% in Block 42 and up to 15% in Block 45 in each commercial discovery. Staatsolie will pay its portion of development and production costs in a commercial development in which it participates.

(9)	License expiration date can be extended beyond the current exploration period upon completion of required work program and subject to additional work obligations.

(10)	Our U.S. Gulf of Mexico blocks can be held by continued operations, and the lease periods on blocks that are held by continued operations extend as long as governmental approved operations continue on the relevant block. This can extend the license expiration to a date later than 2029.

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(1)	Totals within the table may not add as a result of rounding.

(2)	Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split between the WCTP Block and DT Block.

(3)

These reserves include the estimated quantities of fuel gas required to operate the Jubilee and TEN FPSOs during normal field operations and the associated gas forecasted to be exported from TEN. This volume of associated gas is included as of December 31, 2017 as a result of the finalization of the TAG GSA. If and when a subsequent gas sales agreement is executed for Jubilee, a portion of the remaining Jubilee gas may be recognized as reserves. If and when a gas sales agreement and the related infrastructure are in place for the TEN fields non-associated gas, a portion of the remaining gas may be recognized as reserves.

(4)

We disclosed our share of reserves that were accounted for by the equity method. Effective of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward.

(5)	The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.

(6)	All of our proved undeveloped reserves are expected to be developed within six years or less. Proved undeveloped reserves expected to be developed beyond five years are related to long-term projects which will be completed under a continuous drilling program.

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(1)

PV‑10 represents the present value of estimated future revenues to be generated from the production of proved oil and natural gas reserves, net of future development and production costs, royalties, additional oil entitlements and future tax expense levied at an asset level, using prices based on an average of the first‑day‑of‑the‑months throughout 2019 and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non‑property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10% to reflect the timing of future cash flows. PV‑10 is a non‑GAAP financial measure and often differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of future income tax expense related to proved oil and gas reserves levied at a corporate parent level on future net revenues. However, it does include the effects of future tax expense levied at an asset level. Neither PV‑10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas assets. PV‑10 should not be considered as an alternative to the Standardized Measure as computed under GAAP; however, we and others in the industry use PV‑10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific corporate tax characteristics of such entities.

(2)

Standardized Measure represents the present value of estimated future cash inflows to be generated from the production of proved oil and natural gas reserves, net of future development and production costs, future income tax expense related to our proved oil and gas reserves levied at a corporate parent and intermediate subsidiary level, royalties, additional oil entitlements and future tax expense levied at an asset level, without giving effect to hedging activities, non‑property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10% to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV‑10. Standardized Measure often differs from PV‑10 because Standardized Measure includes the effects of future income tax expense related to our proved oil and gas reserves levied at a corporate parent level on future net revenues.

(3)	This amount represents the unweighted arithmetic average first‑day‑of‑the‑month prices for the prior 12 months at December 31, 2019 for the respective benchmark. The benchmark price was adjusted for handling fees, transportation fees, quality, and a regional price differential.

(4)	The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.

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(1)

Net acreage based on Kosmos’ participating interests, before the exercise of any options or back‑in rights, except for our net acreage associated with the Jubilee, TEN, and Greater Tortue Ahmeyim fields, which are after the exercise of options or back‑in rights. Our net acreage in Ghana may be affected by any redetermination of interests in the Jubilee Unit and our net acreage in Mauritania and Senegal may be affected by any redetermination of interests in the Greater Tortue Ahmeyim Unit.

(2)	The Exploration Period of the WCTP petroleum contract and DT petroleum contract has expired. The undeveloped area reflected in the table above represents acreage within our discovery areas that were not subject to relinquishment on the expiry of the Exploration Period.

(3)	Formal withdrawal notice on STP Block 12 was communicated to partners on December 13, 2019 and will be effective January 31, 2020.

(1)	Of the 149 productive wells, 37 (gross) or 8.70 (net) have multiple completions within the wellbore.

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(1)	As of December 31, 2019, nine exploratory and appraisal wells have been excluded from the table until a determination is made if the wells have found proved reserves. Also excluded from the table are 16 development wells awaiting completion. These wells are shown as “Wells Suspended or Waiting on Completion” in the table below.

(2)	A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled.

(3)	A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be a productive well, as opposed to the year the well was drilled.

(4)	Represents activity from the U.S. Gulf of Mexico after the acquisition date.

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•	require the acquisition of various permits before operations commence or for operations to continue;

•	enjoin some or all of the operations or facilities deemed not in compliance with permits;

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•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

•	limit, cap, tax or otherwise restrict emissions of GHG and other air pollutants or otherwise seek to address or minimize the effects of climate change;

•	limit or prohibit drilling activities in certain locations lying within protected or otherwise sensitive areas; and

•	require measures to mitigate or remediate pollution, including pollution resulting from our block partners’ or our contractors’ operations.

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•	changes in supply and demand for oil and natural gas;

•	the actions of the Organization of the Petroleum Exporting Countries;

•	speculation as to the future price of oil and natural gas and the speculative trading of oil and natural gas futures contracts;

•	global economic conditions;

•	political and economic conditions, including embargoes in oil‑producing countries or affecting other oil‑producing activities, particularly in the Middle East, Africa, Russia and Central and South America;

•	the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

•	the level of global oil and natural gas exploration and production activity;

•	the level of global oil inventories and oil refining capacities;

•	weather conditions and natural or man‑made disasters;

•	technological advances affecting energy consumption;

•	governmental regulations and taxation policies;

•	proximity and capacity of transportation facilities;

•	the development and exploitation of alternative fuels or energy sources;

•	the price and availability of competitors’ supplies of oil and natural gas; and

•	the price, availability or mandated use of alternative fuels or energy sources.

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•	the timing and amount of capital expenditures;

•	if the activity is operated by one of our block partners, the operator’s expertise and financial resources;

•	approval of other block partners in drilling wells;

•	the scheduling, pre‑design, planning, design and approvals of activities and processes;

•	selection of technology;

•	the available capacity of processing facilities and related pipelines; and

•	the rate of production of reserves, if any.

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•	actual prices we receive for oil and natural gas;

•	actual cost of development and production expenditures;

•	derivative transactions;

•	the amount and timing of actual production; and

•	changes in governmental regulations or taxation.

•	the scope, rate of progress and cost of our exploration, appraisal, development and production activities;

•	the success of our exploration, appraisal, development and production activities;

•	oil and natural gas prices;

•	our ability to locate and acquire hydrocarbon reserves;

•	our ability to produce oil or natural gas from those reserves;

•	the terms and timing of any drilling and other production‑related arrangements that we may enter into;

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•	the cost and timing of governmental approvals and/or concessions; and

•	the effects of competition by other companies operating in the oil and gas industry.

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•	fires, blowouts, spills, cratering and explosions;

•	mechanical and equipment problems, including unforeseen engineering complications;

•	uncontrolled flows or leaks of oil, well fluids, natural gas, brine, toxic gas or other pollutants or hazardous materials;

•	gas flaring operations;

•	marine hazards with respect to offshore operations;

•	formations with abnormal pressures;

•	pollution, environmental risks, and geological problems; and

•	weather conditions and natural or man‑made disasters.

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•	severe weather, natural or man‑made disasters or acts of God;

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•	delays or decreases in production, the availability of equipment, facilities, personnel or services;

•	delays or decreases in the availability of capacity to transport, gather or process production;

•	military conflicts, civil unrest or political strife; and/or

•	international border disputes.

•	disrupt our operations;

•	require us to incur greater costs for security;

•	restrict the movement of funds or limit repatriation of profits;

•	lead to U.S. government or international sanctions; or

•	limit access to markets for periods of time.

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•	licenses for drilling operations;

•	tax increases, including retroactive claims;

•	unitization of oil accumulations;

•	local content requirements (including the mandatory use of local partners and vendors); and

•	safety, health and environmental requirements, liabilities and obligations, including those related to remediation, investigation or permitting.

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•	delay or denial of drilling permits;

•	shortening of lease terms or reduction in lease size;

•	restrictions or delays on our ability to obtain additional seismic data;

•	restrictions on installation or operation of gathering or processing facilities;

•	restrictions on the use of certain operating practices;

•	legal challenges or lawsuits;

•	individuals requesting more analysis and disclosure of environmental and climate change-related risks;

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•	damaging publicity about us;

•	increased regulation;

•	increased costs of doing business;

•	reduction in demand for our products; and

•	other adverse effects on our ability to develop our properties and/or undertake production operations.

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•	production is less than the volume covered by the derivative instruments;

•	the counter‑party to the derivative instrument defaults on its contract obligations; or

•	there is an increase in the differential between the underlying price and actual prices received in the derivative instrument.

•	our investments, loans and advances and certain of our subsidiaries’ payment of dividends and other restricted payments;

•	our incurrence of additional indebtedness;

•	the granting of liens, other than liens created pursuant to the commercial debt facility, revolving credit facility or the indenture governing the Senior Notes and certain permitted liens;

•	mergers, consolidations and sales of all or a substantial part of our business or licenses;

•	the hedging, forward sale or swap of our production of crude oil or natural gas or other commodities;

•	the sale of assets (other than production sold in the ordinary course of business); and

•	in the case of the commercial debt facility and the revolving credit facility, our capital expenditures that we can fund with the proceeds of our commercial debt facility, and revolving credit facility.

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•	a significant portion or all of our cash flows, when generated, could be used to service our indebtedness;

•	a high level of indebtedness could increase our vulnerability to general adverse economic and industry conditions;

•	the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

•	a high level of indebtedness may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness could prevent us from pursuing;

•	our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

•	additional hedging instruments may be required as a result of our indebtedness;

•	a high level of indebtedness may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then‑outstanding bank borrowings; and

•	a high level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

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•	recoverable reserves;

•	future oil and natural gas prices and their appropriate differentials;

•	development and operating costs; and

•	potential environmental and other liabilities.

•	diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

•	the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

•	difficulty associated with coordinating geographically separate organizations; and

•	the challenge of attracting and retaining personnel associated with acquired operations.

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•	the price of oil and natural gas;

•	the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;

•	operational incidents;

•	regulatory developments in the United States and foreign countries where we operate;

•	the recruitment or departure of key personnel;

•	quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us;

•	market conditions in the industries in which we compete and issuance of new or changed securities;

•	analysts’ reports or recommendations;

•	the failure of securities analysts to cover our common stock or changes in financial estimates by analysts;

•	the inability to meet the financial estimates of analysts who follow our common stock;

•	the issuance or sale of any additional securities of ours;

•	investor perception of our company and of the industry in which we compete; and

•	general economic, political and market conditions.

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(1)

For the year ended December 31, 2018, we have presented our 50% share of the results of operations, including our basis difference which is reflected in depletion, depreciation and amortization. Under the equity method of accounting, we only recognize our share of the net income of KTIPI as adjusted for our basis differential, which is recorded in (Gain) loss on equity method investments, net in the consolidated statement of operations.

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(1)

For the year ended December 31, 2017, we have presented our 50% share of the results of operations from the date of acquisition, November 28, 2017 through December 31, 2017, including our basis difference which is reflected in depletion, depreciation and amortization. Under the equity method of accounting, we only recognize our share of the net income of KTIPI as adjusted for our basis differential, which is recorded in (Gain) loss on equity method investments, net in the consolidated statement of operations.

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

•	execute appraisal and exploration activities in a number of our exploration license areas; and

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•	Approximately 40% related to exploitation and production optimization activities across our Ghana, Equatorial Guinea and U.S. Gulf of Mexico assets

•	Approximately 50% related to our infrastructure-led exploration and development activities across Equatorial Guinea and the U.S. Gulf of Mexico

•	Approximately 10% related to basin opening exploration efforts across our portfolio

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•	the field life cover ratio (as defined in the glossary), not less than 1.30x; and

•	the loan life cover ratio (as defined in the glossary), not less than 1.10x; and

•	the debt cover ratio (as defined in the glossary), not more than 3.5x; and

•	the interest cover ratio (as defined in the glossary), not less than 2.25x.

•	the debt cover ratio (as defined in the glossary), not more than 3.5x; and

•	the interest cover ratio (as defined in the glossary), not less than 2.25x.

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(1)

Includes the scheduled maturities for the $650.0 million aggregate principal amount of Senior Notes issued in April 2019 and borrowings under the Facility. The scheduled maturities of debt related to the Facility are based on, as of December 31, 2019, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. 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)	Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves at the reporting date and commitment fees related to the Facility and Corporate Revolver and interest on the Senior Notes.

(3)	Primarily relates to corporate office and foreign office leases.

(4)

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 11 of Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding these liabilities.

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(1)	The amounts included in the table represent principal maturities only. The scheduled maturities of debt are based on the level of borrowings and the available borrowing base as of December 31, 2019. 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)	Based on outstanding borrowings as noted in (1) above and the LIBOR yield curves plus applicable margin at the reporting date. Excludes commitment fees related to the Facility and Corporate Revolver.

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•	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.

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•	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.

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(1)	Represents call option contracts sold to counterparties to enhance other derivative positions.

(2)	Fair values are based on the average forward oil prices on December 31, 2019.

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1.

ASC 842 requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of our leases where we are the lessee do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Our incremental borrowing rate for a lease is the rate of interest we would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms.

2.	The lease term for all of our leases includes the non-cancellable period of the lease plus any additional periods covered by either an option to extend (or not to terminate) the lease that we are reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor.

3.

Lease payments included in the measurement of the lease asset or liability comprise the following: fixed payments (including in-substance fixed payments), variable payments that depend on index or rate, and the exercise price of a lessee option to purchase the underlying asset if we are reasonably certain to exercise. Amounts expected to be payable under residual value guarantee are also lease payments included in the measurement of the lease liability.

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•	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.

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(1)	Based on 34,993,585 shares of common stock issued at a price of $8.80 per share, which was the opening Kosmos common stock price on September 14, 2018, the closing date of the acquisition.

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(1)	Represents the reclassification of Nearly Headless Nick well costs associated with the DGE acquisition in 2018 and inclusion of the Mahogany and Teak discoveries in the Jubilee Unit in 2017.

(2)	Represents the reduction in basis of suspended well costs associated with the Mauritania and Senegal transactions with BP

(3)	Primarily related to Akasa and Wawa wells as we wrote off $38.1 million and $13.6 million, respectively, of previously capitalized costs exploratory well costs to exploration expense during the third quarter of 2018. These impairments are included in our Ghana segment.

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(1)	The basis difference, which is associated with oil and gas properties and subject to amortization, has been allocated to the Ceiba Field and Okume Complex. We amortize the basis difference using the unit-of-production method.

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(1)	Includes $32.8 million and $40.5 million of unamortized deferred financing costs related to the Facility and $9.1 million and $14.0 million of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31, 2019 and December 31, 2018, respectively.

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(1)

Includes the scheduled maturities for the $650.0 million aggregate principal amount of Senior Notes issued in April 2019 and borrowings under the Facility. The scheduled maturities of debt related to the Facility are based on, as of December 31, 2019, our level of borrowings and our estimated future available borrowing base commitment levels in future periods. 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.

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(1)	Represents call option contracts sold to counterparties to enhance other derivative positions.

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(1)	Includes net deferred premiums payable of $1.0 million and $1.6 million related to commodity derivative contracts as of December 31, 2019 and 2018, respectively.

(2)	Includes net deferred premiums payable of $0.3 million and $1.3 million related to commodity derivative contracts as of December 31, 2019 and 2018, respectively.

(3)	Includes net deferred premiums payable of $5.5 million and $18.0 million related to commodity derivative contracts as of December 31, 2019 and 2018, respectively.

(4)	Includes net deferred premiums payable of $0.3 million and $0.5 million related to commodity derivative contracts as of December 31, 2019 and 2018, respectively.

(1)	Amounts represent the change in fair value of our provisional oil sales contracts.

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•	Level 1—quoted prices for identical assets or liabilities in active markets.

•	Level 2—quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means.

•	Level 3—unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

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(1)

On December 28, 2018, we changed our jurisdiction of incorporation from Bermuda to the State of Delaware. Kosmos Energy Ltd. discontinued as a Bermuda exempted company pursuant to Section 132G of the Companies Act 1981 of Bermuda and, pursuant to Section 265 of the General Corporation Law of the State of Delaware (the “DGCL”), continued its existence under the DGCL as a corporation organized in the State of Delaware. As a result, the statutory tax rate for the 2019 and 2018 reconciliation of income tax expense is the U.S. statutory tax rate of 21%. Our 2017 reconciliation of income tax expense is based on the Bermuda statutory tax rate of 0%.

(2)	The effective tax rate during the years ended December 31, 2019, 2018 and 2017, were impacted by losses of $132.1 million, $261.2 million and $164.4 million, respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits or where there are valuation allowances offsetting the corresponding deferred tax assets.

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(1)

Our service vesting restricted stock awards represent participating securities because they participate in non-forfeitable dividends with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Our restricted stock awards with market and service vesting criteria and all restricted stock units are not considered to be participating securities and, therefore, are excluded from the basic net income (loss) per share calculation. Our service vesting restricted stock awards do not participate in undistributed net losses because they are not contractually obligated to do so and, therefore, are excluded from the basic net income (loss) per share calculation in periods we are in a net loss position. All restricted stock awards were fully vested in January 2018.

(2)	For the years ended December 31, 2019, 2018 and 2017, we excluded 15.3 million, 10.6 million and 12.9 million outstanding restricted stock awards and restricted stock units, respectively, from the computations of diluted net income per share because the effect would have been anti‑dilutive. All restricted stock awards were fully vested in January 2018.

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(1)	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, in our petroleum contracts.

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(1)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.

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(1)	Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion, depreciation and amortization for the year ended December 31, 2018, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.

(2)	Represents activity commencing September 14, 2018, the DGE acquisition date.

(3)	Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations.

(4)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.

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(1)	Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion, depreciation and amortization for the year ended December 31, 2017, except for capital expenditures. See Note 7 - Equity Method Investments for additional information regarding our equity method investments.

(2)	Includes elimination of proportionate consolidation amounts recorded for KTIPI to reconcile to (Gain) loss on equity method investments, net as reported in the consolidated statements of operations.

(3)	Interest expense is recorded based on actual third-party and intercompany debt agreements. Capitalized interest is recorded on the business unit where the assets reside.

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(1)	Unsuccessful well costs are included in oil and gas assets when incurred.

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(1)	The sum of proved developed reserves and proved undeveloped reserves may not add to net proved developed and undeveloped reserves as a result of rounding.

(2)	The increase in proved reserves is a result of a 16 MMBbl increase associated in Jubilee related to the approval of the Greater Jubilee Full Field Development Plan (GJFFDP) and an 8 MMBoe increase associated with positive revisions to the TEN fields.

(3)	The increase in purchase of minerals in place is related to Equatorial Guinea, representing the reserves associated with our equity method investment.

(4)

The increase in proved reserves is a result of an increase of 8.2 MMBbl in Greater Jubilee related to positive drilling results and subsequent increased original oil in place, and optimized development plan. Changes at TEN include a positive revision of 8.8 MMBoe related to original oil in place adjustments based on the latest static modeling, and development plan updates. Changes at Equatorial Guinea include an increase of 6.3 MMBbl due to production optimization and plans for new drilling. Changes at the Gulf of Mexico (GoM) include an increase of 2.9 MMBoe related to strong performance of certain fields and the Gladden Deep discovery.

(5)	The increase in purchase of minerals in place is related to the DGE acquisition completed in September 2018.

(6)

We disclosed our share of reserves that were accounted for by the equity method. Effective of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward.

(7)	The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.

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(1)	Includes Africa (excluding Ghana, Equatorial Guinea, Mauritania and Senegal), Europe and South America.

(2)	For year ended December 31, 2017, represents 50% interest in KTIPI costs incurred from the date of acquisition through December 31, 2017.

(3)	Represents cash paid to acquire 50% interest in KTIPI.

(4)	Mauritania/Senegal is net of the farm-out to BP in 2017.

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(1)

The Company was a tax exempt company incorporated pursuant to the laws of Bermuda at December 31, 2017. The Company was not subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent level. Accordingly, the Company’s Standardized Measure for the years ended December 31, 2018 and 2017, respectively, only reflect the effects of future tax expense levied at an asset level.

(2)	The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.

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(1)

The Company was a tax exempt company incorporated pursuant to the laws of Bermuda at December 31, 2017 and 2016. The Company was not subject to future income tax expense related to its proved oil and gas reserves levied at a corporate parent level. Accordingly, the Company’s Standardized Measure for the years ended December 31, 2018 and 2017, respectively, only reflect the effects of future tax expense levied at an asset level.

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(2)

We disclosed our share of reserves that were accounted for by the equity method. Effective of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.4% undivided participating interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex is accounted for under the proportionate consolidation method of accounting going forward.

(3)	The Tortue Phase 1 SPA was signed on February 11, 2020, resulting in approximately 100 MMBoe of proved undeveloped reserves being recognized at that time as evaluated by the company's independent reserve auditor Ryder Scott, LP.

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(1)	The sum of the quarterly earnings per share information may not add to the annual earnings per share information as a result of rounding.

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(a)	The following documents are filed as part of this report:

(1)	Financial statements

(2)	Financial statement schedules

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