(Mark One)
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ý
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2018
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☐
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Delaware
(State or other jurisdiction of
incorporation or organization)
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98‑0686001
(I.R.S. Employer
Identification No.)
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8176 Park Lane
Dallas, Texas
(Address of principal executive offices)
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75231
(Zip Code)
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Title of each class
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Name of each exchange on which registered:
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Common Stock $0.01 par value
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New York Stock Exchange
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London Stock Exchange
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Large accelerated filer ☒
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Accelerated filer ☐
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Non‑accelerated filer ☐
(Do not check if a smaller reporting company)
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Smaller reporting company ☐
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Emerging growth company ☐
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Page
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“2D seismic data”
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Two‑dimensional seismic data, serving as interpretive data that allows a view of a vertical cross‑section beneath a prospective area.
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“3D seismic data”
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Three‑dimensional seismic data, serving as geophysical data that depicts the subsurface strata in three dimensions. 3D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic data.
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“API”
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A specific gravity scale, expressed in degrees, that denotes the relative density of various petroleum liquids. The scale increases inversely with density. Thus lighter petroleum liquids will have a higher API than heavier ones.
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“ASC”
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Financial Accounting Standards Board Accounting Standards Codification.
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“ASU”
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Financial Accounting Standards Board Accounting Standards Update.
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“Barrel” or “Bbl”
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A standard measure of volume for petroleum corresponding to approximately 42 gallons at 60 degrees Fahrenheit.
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“BBbl”
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Billion barrels of oil.
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“BBoe”
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Billion barrels of oil equivalent.
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“Bcf”
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Billion cubic feet.
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“Boe”
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Barrels of oil equivalent. Volumes of natural gas converted to barrels of oil using a conversion factor of 6,000 cubic feet of natural gas to one barrel of oil.
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“Boepd”
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Barrels of oil equivalent per day.
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“Bopd”
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Barrels of oil per day.
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“Bwpd”
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Barrels of water per day.
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“Debt cover ratio”
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The “debt cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) total long‑term debt less cash and cash equivalents and restricted cash, to (y) the aggregate EBITDAX (see below) of the Company for the previous twelve months.
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“Developed acreage”
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The number of acres that are allocated or assignable to productive wells or wells capable of production.
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“Development”
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The phase in which an oil or natural gas field is brought into production by drilling development wells and installing appropriate production systems.
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“Dry hole” or "Unsuccessful well"
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A well that has not encountered a hydrocarbon bearing reservoir expected to produce in commercial quantities.
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“EBITDAX”
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Net income (loss) plus (i) exploration expense, (ii) depletion, depreciation and amortization expense, (iii) equity‑based compensation expense, (iv) unrealized (gain) loss on commodity derivatives (realized losses are deducted and realized gains are added back), (v) (gain) loss on sale of oil and gas properties, (vi) interest (income) expense, (vii) income taxes, (viii) loss on extinguishment of debt, (ix) doubtful accounts expense and (x) similar other material items which management believes affect the comparability of operating results. The Facility EBITDAX definition includes 50% of the EBITDAX adjustments of Kosmos-Trident International Petroleum Inc and includes Last Twelve Months ("LTM") EBITDAX for any acquisitions and excludes LTM EBITDAX for any divestitures.
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“E&P”
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Exploration and production.
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“FASB”
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Financial Accounting Standards Board.
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“Farm‑in”
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An agreement whereby a party acquires a portion of the participating interest in a block from the owner of such interest, usually in return for cash and/or for taking on a portion of future costs or other performance by the assignee as a condition of the assignment.
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“Farm‑out”
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An agreement whereby the owner of the participating interest agrees to assign a portion of its participating interest in a block to another party for cash and/or for the assignee taking on a portion of future costs and/or other work as a condition of the assignment.
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“Field life cover ratio”
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The “field life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) the forecasted net present value of net cash flow through depletion plus the net present value of the forecast of certain capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
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"FLNG"
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Floating liquified natural gas.
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“FPS”
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Floating production system.
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“FPSO”
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Floating production, storage and offloading vessel.
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“Interest cover ratio”
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The “interest cover ratio” is broadly defined, for each applicable calculation date, as the ratio of (x) the aggregate EBITDAX (see above) of the Company for the previous twelve months, to (y) interest expense less interest income for the Company for the previous twelve months.
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“Loan life cover ratio”
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The “loan life cover ratio” is broadly defined, for each applicable forecast period, as the ratio of (x) net present value of forecasted net cash flow through the final maturity date of the Facility plus the net present value of forecasted capital expenditures incurred in relation to the Ghana and Equatorial Guinea assets, to (y) the aggregate loan amounts outstanding under the Facility.
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"LNG"
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Liquefied natural gas.
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“MBbl”
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Thousand barrels of oil.
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“MBoe”
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Thousand barrels of oil equivalent.
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“Mcf”
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Thousand cubic feet of natural gas.
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“Mcfpd”
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Thousand cubic feet per day of natural gas.
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“MMBbl”
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Million barrels of oil.
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“MMBoe”
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Million barrels of oil equivalent.
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"MMBtu"
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Million British thermal units
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“MMcf”
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Million cubic feet of natural gas.
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“MMcfd”
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Million cubic feet per day of natural gas.
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“Natural gas liquid” or “NGL”
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Components of natural gas that are separated from the gas state in the form of liquids. These include propane, butane, and ethane, among others.
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“Petroleum contract”
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A contract in which the owner of hydrocarbons gives an E&P company temporary and limited rights, including an exclusive option to explore for, develop, and produce hydrocarbons from the lease area.
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“Petroleum system”
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A petroleum system consists of organic material that has been buried at a sufficient depth to allow adequate temperature and pressure to expel hydrocarbons and cause the movement of oil and natural gas from the area in which it was formed to a reservoir rock where it can accumulate.
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“Plan of development” or “PoD”
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A written document outlining the steps to be undertaken to develop a field.
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“Productive well”
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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 well.
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“Prospect(s)”
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A potential trap that may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of these fail neither oil nor natural gas may be present, at least not in commercial volumes.
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“Proved reserves”
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Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S‑X 4‑10(a)(2).
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“Proved developed reserves”
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Those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
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“Proved undeveloped reserves”
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Those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
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“Stratigraphy”
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The study of the composition, relative ages and distribution of layers of sedimentary rock.
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“Stratigraphic trap”
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A stratigraphic trap is formed from a change in the character of the rock rather than faulting or folding of the rock and oil is held in place by changes in the porosity and permeability of overlying rocks.
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“Structural trap”
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A topographic feature in the earth’s subsurface that forms a high point in the rock strata. This facilitates the accumulation of oil and gas in the strata.
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“Structural‑stratigraphic trap”
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A structural‑stratigraphic trap is a combination trap with structural and stratigraphic features.
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“Trap”
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A configuration of rocks suitable for containing hydrocarbons and sealed by a relatively impermeable formation through which hydrocarbons will not migrate.
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“Undeveloped acreage”
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Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains discovered resources.
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•
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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;
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•
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uncertainties inherent in making estimates of our oil and natural gas data;
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the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;
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projected and targeted capital expenditures and other costs, commitments and revenues;
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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;
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•
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our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;
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•
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the ability to obtain financing and to comply with the terms under which such financing may be available;
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•
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the volatility of oil, natural gas and NGL prices;
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the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;
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•
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the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
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•
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other competitive pressures;
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potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;
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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;
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•
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cost of compliance with laws and regulations;
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changes in environmental, health and safety or climate change or greenhouse gas (“GHG”) laws and regulations or the implementation, or interpretation, of those laws and regulations;
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adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;
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environmental liabilities;
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geological, geophysical and other technical and operations problems including drilling and oil and gas production and processing;
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military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;
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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;
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our ability to meet our obligations under the agreements governing our indebtedness;
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the availability and cost of financing and refinancing our indebtedness;
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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;
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the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;
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our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and
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other risk factors discussed in the “Item 1A. Risk Factors” section of this annual report on Form 10‑K.
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Geographic Area
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Sales Volumes (Net to Kosmos)
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Percentage of Total Sales Volumes
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Revenue
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Year-End Estimated Proved Reserves(1)
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Percentage of Total Estimated Proved Reserves
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(in MMboe)
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(in thousands)
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(in MMboe)
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Ghana
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10.7
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58
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%
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$
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739,070
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89.7
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54
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%
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U.S. Gulf of Mexico(2)
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2.6
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14
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147,596
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51.1
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30
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Total Kosmos
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13.3
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886,666
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140.8
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Equatorial Guinea(3)
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5.2
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28
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360,650
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26.6
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16
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Total
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18.5
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100
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%
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1,247,316
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167.4
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100
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%
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(1)
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For information concerning our estimated proved reserves as of
December 31, 2018
, see “—Our Reserves.”
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(2)
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Represents contributions from the U.S. Gulf of Mexico after the acquisition date.
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(3)
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Includes our 50% share from our equity method investment in Equatorial Guinea. 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. Effective as of January 1, 2019, our equity method investment in Equatorial Guinea was converted to an undivided interest in Block G.
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Kosmos
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Participating
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License
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Fields
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License
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Interest
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Operator
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Stage
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Expiration
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Ghana(1)
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Jubilee
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WCTP/DT
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(2)
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24.1
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%
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(2)
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Tullow
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Production
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2034
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TEN
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DT
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17.0
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%
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(4)
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Tullow
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Production
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2036
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U.S. Gulf of Mexico(1)
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Barataria
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MC 521
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22.5
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%
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Kosmos
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Production
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(10)
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Big Bend
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MC 697 / 698 / 742
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5.3
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%
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Fieldwood
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Production
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(10)
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Don Larsen
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EB 598
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20.0
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%
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Anadarko
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Production
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(10)
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Gladden
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MC 800
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20.0
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%
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W&T
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Production
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(10)
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Kodiak
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MC 727 / 771
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29.1
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%
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Kosmos
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Production
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(10)
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Marmalard
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MC 255 / 300
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11.8
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%
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LLOG
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Production
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(10)
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Nearly Headless Nick
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MC 387
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22.0
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%
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LLOG
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Development
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(10)
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Danny Noonan
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EC 381
GB 463 / 506
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Various
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(5)
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Talos
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Production
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(10)
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Odd Job
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MC 214 / 215
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Various
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(6)
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Kosmos
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Production
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(10)
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Sargent
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GB 339
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50.0
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%
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Kosmos
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Production
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(10)
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SOB II
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MC 431
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11.8
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%
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LLOG
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Production
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(10)
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S. Santa Cruz
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MC 563
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40.5
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%
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Kosmos
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Production
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(10)
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Tornado
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GC 281
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35.0
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%
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Talos
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Production
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(10)
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Mauritania
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Greater Tortue Ahmeyim
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Block C8
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(3)
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29.0
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%
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(7)
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BP
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Development
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2049
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(11)
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Marsouin
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Block C8
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28.0
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%
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(7)
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BP
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Appraisal
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2019
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(12)
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Senegal
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Greater Tortue Ahmeyim
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Saint Louis Offshore Profond
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(3)
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29.0
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%
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(8)
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BP
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(8)
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Development
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2044
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(11)
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Teranga
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Cayar Offshore Profond
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30.0
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%
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(8)
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BP
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(8)
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Appraisal
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2021
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Yakaar
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Cayar Offshore Profond
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30.0
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%
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(8)
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BP
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(8)
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Appraisal
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2021
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Equatorial Guinea(1)
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Ceiba Field and Okume Complex
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Block G
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40.4
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%
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(9)
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Trident
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(9)
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Production
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2034
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(1)
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For information concerning our estimated proved reserves as of
December 31, 2018
, see “—Our Reserves.”
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(2)
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The Jubilee Field straddles the boundary between the West Cape Three Points (“WCTP”) petroleum contract and the Deepwater Tano (“DT”) petroleum contract offshore Ghana. To optimize resource recovery in this field, we entered into the Unitization and Unit Operating Agreement (the “Jubilee UUOA”) in July 2009 with the Ghana National Petroleum Corporation (“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.
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(3)
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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 a Unitization and Unit Operating Agreement ("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 areas.
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(4)
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Our paying interest on development activities in the TEN fields is 19%.
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(5)
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Our interests in blocks EC 381, GB 463 and GB 506 are 30%, 15% and 30%, respectively.
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(6)
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Our interests in blocks MC 214 and MC 215 are 61.1% and 54.9%, respectively.
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(7)
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SMHPM has the option to acquire up to an additional 4% paying interests in a commercial development on Block C8. These interest percentages do not give effect to the exercise of such option.
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(8)
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PETROSEN has the option to acquire up to an additional 10% paying interests 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.
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(9)
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Kosmos owned a 50% interest in KTIPI which held an 85% interest in the Ceiba Field and Okume Complex through its wholly-owned subsidiary, Kosmos-Trident Equatorial Guinea Inc. ("KTEGI"), representing a 40.375% net indirect interest to Kosmos. Kosmos and Trident provided operational management and support to KTEGI, who is operator of the Ceiba Field and Okume Complex. Effective January 1, 2019, our outstanding shares in KTIPI were transferred to Trident Energy ("Trident") in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex and Trident became the operator. As a result, our interest in the Ceiba Field and Okume Complex will be accounted for under the proportionate consolidation method of accounting going forward.
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(10)
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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.
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(11)
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License expiration date can be extended by an additional ten years subject to certain conditions being met.
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(12)
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License expiration date can be extended beyond the current exploration period upon completion of required work program and subject to additional work obligations.
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Kosmos Average
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License
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Number of
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Participating
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Expiration
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Country
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Blocks
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Interest
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Operator(s)
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Range
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Cote D'Ivoire
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5
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45.0%
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(1)
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Kosmos
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2020
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(8)
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Equatorial Guinea
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4
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40.0%
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(2)
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Kosmos
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2020-2021
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(8)
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Mauritania
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5
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25.4%
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(3)
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BP, Total
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2019-2020
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(8)
|
Namibia
|
|
1
|
|
45.0%
|
|
(4)
|
|
Shell
|
|
2019
|
(8)
|
Sao Tome and Principe
|
|
6
|
|
45.0%
|
|
(5)
|
|
Kosmos, BP, Galp
|
|
2019-2022
|
(8)
|
Senegal
|
|
2
|
|
30.0%
|
|
(6)
|
|
BP
|
|
2020-2021
|
|
Suriname
|
|
2
|
|
41.7%
|
|
(7)
|
|
Kosmos
|
|
2020-2021
|
(8)
|
U.S. Gulf of Mexico
|
|
22
|
|
54.0%
|
|
|
|
Kosmos, Chevron, LLOG, Murphy
|
|
2019-2028
|
(9)
|
(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 acquire a participating interest in the discovery area between 10% and 14% (blocks C8, C12 and C13), 10% and 15% (Block C18) 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 participating 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.
|
(6)
|
PETROSEN has the option to acquire 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)
|
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.
|
(8)
|
License expiration date can be extended beyond the current exploration period upon completion of required work program and subject to additional work obligations.
|
(9)
|
Our U.S. Gulf of Mexico blocks can be held by continued operations, and the lease periods extend as long as governmental approved operations continue on the relevant block.
|
|
2018 Net Proved Reserves(1)
|
|
2017 Net Proved Reserves(1)
|
|
2016 Net Proved Reserves(1)
|
|||||||||||||||||||||
|
Oil,
Condensate,
NGLs
|
|
Natural
Gas(2)
|
|
Total
|
|
Oil,
Condensate,
NGLs
|
|
Natural
Gas(2)
|
|
Total
|
|
Oil,
Condensate,
NGLs
|
|
Natural
Gas(2)
|
|
Total
|
|||||||||
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBoe)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBoe)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBoe)
|
|||||||||
Reserves Category
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved developed
|
82
|
|
|
57
|
|
|
91
|
|
|
59
|
|
|
38
|
|
|
65
|
|
|
64
|
|
|
13
|
|
|
66
|
|
Proved undeveloped(3)
|
45
|
|
|
28
|
|
|
50
|
|
|
23
|
|
|
11
|
|
|
24
|
|
|
10
|
|
|
2
|
|
|
11
|
|
Total Kosmos
|
127
|
|
|
85
|
|
|
141
|
|
|
82
|
|
|
49
|
|
|
89
|
|
|
74
|
|
|
15
|
|
|
77
|
|
Equity method investment(4)
|
24
|
|
|
14
|
|
|
27
|
|
|
19
|
|
|
13
|
|
|
21
|
|
|
|
|
|
|
|
|||
Total reserves
|
151
|
|
|
99
|
|
|
167
|
|
|
100
|
|
|
61
|
|
|
110
|
|
|
|
|
|
|
|
(1)
|
Our reserves associated with the Jubilee Field are based on the 54.4%/45.6% redetermination split, between the WCTP Block and DT Block. Totals within the table may not add as a result of rounding.
|
(2)
|
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 TEN Associated-Gas Gas Sales Agreement ("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.
|
(3)
|
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.
|
(4)
|
We disclose our share of reserves that are accounted for by the equity method.
|
|
Estimated Future Net Revenues(4)
|
||||||||||
|
(in millions except $/Bbl)
|
||||||||||
|
Kosmos
|
|
Equity Method Investment
|
|
Total
|
||||||
|
|
|
|
|
|
||||||
Estimated future net revenues
|
$
|
5,487
|
|
|
$
|
774
|
|
|
$
|
6,261
|
|
Present value of estimated future net revenues:
|
|
|
|
|
|
||||||
PV-10(1)
|
$
|
3,928
|
|
|
$
|
705
|
|
|
$
|
4,633
|
|
Future income tax expense (levied at a corporate parent and intermediate subsidiary level)
|
(1,431
|
)
|
|
(416
|
)
|
|
(1,847
|
)
|
|||
Discount of future income tax expense (levied at a corporate parent and intermediate subsidiary level) at 10% per annum
|
413
|
|
|
102
|
|
|
515
|
|
|||
Standardized Measure(2)
|
$
|
2,910
|
|
|
$
|
391
|
|
|
$
|
3,301
|
|
|
|
|
|
|
|
|
|||||
Benchmark Dated Brent oil price($/Bbl)(3)
|
|
|
|
|
$
|
71.54
|
|
||||
Benchmark HLS oil price($/Bbl)(3)
|
|
|
|
|
$
|
70.20
|
|
||||
Benchmark Henry Hub gas price($/MMBtu)(3)
|
|
|
|
|
$
|
3.10
|
|
(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
2018
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, 2018
for the respective benchmark. The benchmark price was adjusted for handling fees, transportation fees, quality, and a regional price differential.
|
(4)
|
Future net revenues and PV-10 have been adjusted from the reserve report which is based on the entitlements method as we account for oil and gas revenues under the sales method of accounting.
|
|
Developed Area
|
|
Undeveloped Area
|
|
|
|
|
||||||||||
|
(Acres)
|
|
(Acres)
|
|
Total Area (Acres)
|
||||||||||||
|
Gross
|
|
Net(1)
|
|
Gross
|
|
Net(1)
|
|
Gross
|
|
Net(1)
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
(In thousands)
|
||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Ghana(2)
|
163
|
|
|
32
|
|
|
34
|
|
|
7
|
|
|
197
|
|
|
39
|
|
Cote d'Ivoire
|
—
|
|
|
—
|
|
|
4,143
|
|
|
1,865
|
|
|
4,143
|
|
|
1,865
|
|
Equatorial Guinea(3)
|
—
|
|
|
—
|
|
|
2,355
|
|
|
942
|
|
|
2,355
|
|
|
942
|
|
Mauritania
|
—
|
|
|
—
|
|
|
9,275
|
|
|
2,172
|
|
|
9,275
|
|
|
2,172
|
|
Namibia
|
—
|
|
|
—
|
|
|
3,039
|
|
|
1,368
|
|
|
3,039
|
|
|
1,368
|
|
Sao Tome and Principe
|
—
|
|
|
—
|
|
|
9,255
|
|
|
4,270
|
|
|
9,255
|
|
|
4,270
|
|
Senegal
|
—
|
|
|
—
|
|
|
2,116
|
|
|
635
|
|
|
2,116
|
|
|
635
|
|
Suriname
|
—
|
|
|
—
|
|
|
2,793
|
|
|
1,142
|
|
|
2,793
|
|
|
1,142
|
|
U.S. Gulf of Mexico
|
127
|
|
|
35
|
|
|
131
|
|
|
70
|
|
|
258
|
|
|
105
|
|
Total Kosmos
|
290
|
|
|
67
|
|
|
33,141
|
|
|
12,471
|
|
|
33,431
|
|
|
12,538
|
|
Equity method investment(4)
|
65
|
|
|
28
|
|
|
—
|
|
|
—
|
|
|
65
|
|
|
28
|
|
Total
|
355
|
|
|
95
|
|
|
33,141
|
|
|
12,471
|
|
|
33,496
|
|
|
12,566
|
|
(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 and TEN 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.
|
(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)
|
In January 2019, we entered into an agreement to acquire Ophir's remaining interest in the block, subject to customary governmental approvals, which will result in Kosmos owning an
80%
interest in Block EG-24. After completion of this transaction, our net acreage in Equatorial Guinea will be 1,292 thousand acres.
|
(4)
|
Represents our 50% interest in KTIPI. Effective as of January 1, 2019, our outstanding shares in KTIPI were transferred to Trident in exchange for a 40.375% undivided interest in the Ceiba Field and Okume Complex. As a result, our interest in the Ceiba Field and Okume Complex will be accounted for under the proportionate consolidation method of accounting going forward.
|
|
Productive
|
|
Productive
|
|
|
|
|
||||||||||
|
Oil Wells
|
|
Gas Wells
|
|
Total
|
||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Ghana
|
41
|
|
|
9.00
|
|
|
—
|
|
|
—
|
|
|
41
|
|
|
9.00
|
|
U.S. Gulf of Mexico
|
17
|
|
|
3.02
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
3.02
|
|
Kosmos Total(1)
|
58
|
|
|
12.02
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|
12.02
|
|
Equity Method Investment(2)(3)
|
96
|
|
|
38.78
|
|
|
—
|
|
|
—
|
|
|
96
|
|
|
38.78
|
|
Total
|
154
|
|
|
50.80
|
|
|
—
|
|
|
—
|
|
|
154
|
|
|
50.80
|
|
(1)
|
Of the 58 productive wells, 20 (gross) or 3.53 (net) have multiple completions within the wellbore.
|
(2)
|
Represents our 50% interest in KTIPI.
|
(3)
|
Of the 96 productive wells, 6 (gross) or 2.42 (net) have multiple completions within the wellbore.
|
|
Exploratory and Appraisal Wells(1)
|
|
Development Wells(1)
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Productive(2)
|
|
Dry(3)
|
|
Total
|
|
Productive(2)
|
|
Dry(3)
|
|
Total
|
|
Total
|
|
Total
|
||||||||||||||||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Ghana
|
—
|
|
|
—
|
|
|
3
|
|
|
0.80
|
|
|
3
|
|
|
0.80
|
|
|
4
|
|
|
0.89
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
0.89
|
|
|
7
|
|
|
1.69
|
|
U.S. Gulf of Mexico(4)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.55
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.55
|
|
|
1
|
|
|
0.55
|
|
Senegal
|
—
|
|
|
—
|
|
|
1
|
|
|
0.60
|
|
|
1
|
|
|
0.60
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.60
|
|
Suriname
|
—
|
|
|
—
|
|
|
2
|
|
|
1.20
|
|
|
2
|
|
|
1.20
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
1.20
|
|
Total
|
—
|
|
|
—
|
|
|
6
|
|
|
2.60
|
|
|
6
|
|
|
2.60
|
|
|
5
|
|
|
1.44
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
1.44
|
|
|
11
|
|
|
4.04
|
|
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Ghana
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Mauritania
|
—
|
|
|
—
|
|
|
2
|
|
|
0.56
|
|
|
2
|
|
|
0.56
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.56
|
|
Total
|
—
|
|
|
—
|
|
|
2
|
|
|
0.56
|
|
|
2
|
|
|
0.56
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.56
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Ghana
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
1.19
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
1.19
|
|
|
7
|
|
|
1.19
|
|
Total
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
1.19
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
1.19
|
|
|
7
|
|
|
1.19
|
|
(1)
|
As of
December 31, 2018
,
seven
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
14
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 contributions from the U.S. Gulf of Mexico after the acquisition date.
|
|
Actively Drilling or
|
|
Wells Suspended or
|
||||||||||||||||||||
|
Completing
|
|
Waiting on Completion
|
||||||||||||||||||||
|
Exploration
|
|
Development
|
|
Exploration
|
|
Development
|
||||||||||||||||
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||
Ghana
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Jubilee Unit
|
—
|
|
|
—
|
|
|
1
|
|
|
0.24
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
1.93
|
|
TEN
|
—
|
|
|
—
|
|
|
2
|
|
|
0.34
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
0.85
|
|
U.S. Gulf of Mexico
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Nearly Headless Nick
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.22
|
|
|
—
|
|
|
—
|
|
Odd Job 214#2
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.61
|
|
Tornado
|
—
|
|
|
—
|
|
|
1
|
|
|
0.35
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Mauritania
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
C8
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
0.84
|
|
|
—
|
|
|
—
|
|
Senegal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Saint Louis Offshore Profond
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
0.30
|
|
|
—
|
|
|
—
|
|
Cayar Profond
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
0.60
|
|
|
—
|
|
|
—
|
|
Total
|
—
|
|
|
—
|
|
|
4
|
|
|
0.93
|
|
|
7
|
|
|
1.96
|
|
|
14
|
|
|
3.39
|
|
•
|
require the acquisition of various permits before operations commence;
|
•
|
enjoin some or all of the operations or facilities deemed not in compliance with permits;
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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;
|
•
|
the cost and timing of governmental approvals and/or concessions; and
|
•
|
the effects of competition by larger companies operating in the oil and gas industry.
|
•
|
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.
|
•
|
severe weather, natural or man‑made disasters or acts of God;
|
•
|
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.
|
•
|
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.
|
•
|
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;
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
|
Total Number
|
|
Average
|
|||
|
of Shares
|
|
Price Paid
|
|||
|
Purchased
|
|
per Share
|
|||
|
(In thousands)
|
|
|
|||
January 1, 2018—January 31, 2018
|
74
|
|
|
$
|
6.85
|
|
February 1, 2018—February 28, 2018
|
—
|
|
|
—
|
|
|
March 1, 2018—March 31, 2018
|
—
|
|
|
—
|
|
|
April 1, 2018—April 30, 2018
|
—
|
|
|
—
|
|
|
May 1, 2018—May 31, 2018
|
—
|
|
|
—
|
|
|
June 1, 2018—June 30, 2018
|
—
|
|
|
—
|
|
|
July 1, 2018—July 31, 2018
|
—
|
|
|
—
|
|
|
August 1, 2018—August 31, 2018
|
—
|
|
|
—
|
|
|
September 1, 2018—September 30, 2018
|
—
|
|
|
—
|
|
|
October 1, 2018—October 31, 2018
|
—
|
|
|
—
|
|
|
November 1, 2018—November 30, 2018
|
35,000
|
|
|
5.38
|
|
|
December 1, 2018—December 31, 2018
|
—
|
|
|
—
|
|
|
Total
|
35,074
|
|
|
5.38
|
|
|
December 31,
|
|||||||||||||||||
|
2013
|
2014
|
2015
|
2016
|
2017
|
2018
|
||||||||||||
Kosmos Energy Ltd. (KOS)
|
$
|
100.00
|
|
$
|
75.05
|
|
$
|
46.51
|
|
$
|
62.70
|
|
$
|
61.27
|
|
$
|
36.40
|
|
S&P 500 (SPX)
|
100.00
|
|
113.68
|
|
115.24
|
|
129.02
|
|
157.17
|
|
150.27
|
|
||||||
Dow Jones U.S. Exploration & Production Index (DWCEXP)
|
100.00
|
|
87.53
|
|
66.34
|
|
83.40
|
|
83.63
|
|
67.49
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(In thousands, except per share data)
|
||||||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil and gas revenue
|
$
|
886,666
|
|
|
$
|
578,139
|
|
|
$
|
310,377
|
|
|
$
|
446,696
|
|
|
$
|
855,877
|
|
Gain on sale of assets
|
7,666
|
|
|
—
|
|
|
—
|
|
|
24,651
|
|
|
23,769
|
|
|||||
Other income, net
|
8,037
|
|
|
58,697
|
|
|
74,978
|
|
|
209
|
|
|
3,092
|
|
|||||
Total revenues and other income
|
902,369
|
|
|
636,836
|
|
|
385,355
|
|
|
471,556
|
|
|
882,738
|
|
|||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil and gas production
|
224,727
|
|
|
126,850
|
|
|
119,367
|
|
|
105,336
|
|
|
100,122
|
|
|||||
Facilities insurance modifications, net
|
6,955
|
|
|
(820
|
)
|
|
14,961
|
|
|
—
|
|
|
—
|
|
|||||
Exploration expenses
|
301,492
|
|
|
216,050
|
|
|
202,280
|
|
|
156,203
|
|
|
93,519
|
|
|||||
General and administrative
|
99,856
|
|
|
68,302
|
|
|
87,623
|
|
|
136,809
|
|
|
135,231
|
|
|||||
Depletion and depreciation
|
329,835
|
|
|
255,203
|
|
|
140,404
|
|
|
155,966
|
|
|
198,080
|
|
|||||
Interest and other financing costs, net
|
101,176
|
|
|
77,595
|
|
|
44,147
|
|
|
37,209
|
|
|
45,548
|
|
|||||
Derivatives, net
|
(31,430
|
)
|
|
59,968
|
|
|
48,021
|
|
|
(210,649
|
)
|
|
(281,853
|
)
|
|||||
Restructuring charges
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,742
|
|
|||||
(Gain)loss on equity method investment
|
(72,881
|
)
|
|
6,252
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other expenses, net
|
(6,501
|
)
|
|
5,291
|
|
|
23,116
|
|
|
5,246
|
|
|
2,081
|
|
|||||
Total costs and expenses
|
953,229
|
|
|
814,691
|
|
|
679,919
|
|
|
386,120
|
|
|
304,470
|
|
|||||
Income (loss) before income taxes
|
(50,860
|
)
|
|
(177,855
|
)
|
|
(294,564
|
)
|
|
85,436
|
|
|
578,268
|
|
|||||
Income tax expense (benefit)
|
43,131
|
|
|
44,937
|
|
|
(10,784
|
)
|
|
155,272
|
|
|
298,898
|
|
|||||
Net income (loss)
|
$
|
(93,991
|
)
|
|
$
|
(222,792
|
)
|
|
$
|
(283,780
|
)
|
|
$
|
(69,836
|
)
|
|
$
|
279,370
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Basic
|
$
|
(0.23
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.74
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
0.73
|
|
Diluted
|
$
|
(0.23
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.74
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
0.72
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted average number of shares used to compute net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Basic
|
404,585
|
|
|
388,375
|
|
|
385,402
|
|
|
382,610
|
|
|
379,195
|
|
|||||
Diluted
|
404,585
|
|
|
388,375
|
|
|
385,402
|
|
|
382,610
|
|
|
386,119
|
|
|
December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015(1)(2)
|
|
2014(1)
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
Cash and cash equivalents
|
$
|
173,515
|
|
|
$
|
233,412
|
|
|
$
|
194,057
|
|
|
$
|
275,004
|
|
|
$
|
554,831
|
|
Total current assets
|
509,700
|
|
|
533,602
|
|
|
475,187
|
|
|
734,148
|
|
|
1,010,476
|
|
|||||
Total property and equipment, net
|
3,459,701
|
|
|
2,317,828
|
|
|
2,708,892
|
|
|
2,322,839
|
|
|
1,784,846
|
|
|||||
Total other assets
|
118,788
|
|
|
341,173
|
|
|
157,386
|
|
|
146,063
|
|
|
131,537
|
|
|||||
Total assets
|
4,088,189
|
|
|
3,192,603
|
|
|
3,341,465
|
|
|
3,203,050
|
|
|
2,926,859
|
|
|||||
Total current liabilities
|
384,308
|
|
|
428,730
|
|
|
370,025
|
|
|
456,741
|
|
|
448,771
|
|
|||||
Total long-term liabilities
|
2,762,403
|
|
|
1,866,761
|
|
|
1,890,241
|
|
|
1,420,796
|
|
|
1,139,129
|
|
|||||
Total shareholders’ equity
|
941,478
|
|
|
897,112
|
|
|
1,081,199
|
|
|
1,325,513
|
|
|
1,338,959
|
|
|||||
Total liabilities and shareholders’ equity
|
4,088,189
|
|
|
3,192,603
|
|
|
3,341,465
|
|
|
3,203,050
|
|
|
2,926,859
|
|
(1)
|
Effective December 31, 2015, the Company adopted new guidance on the presentation of debt issuance costs. This guidance was adopted retrospectively and all prior periods have been adjusted to reflect this change in accounting principle.
|
(2)
|
Effective December 31, 2015, the Company adopted new guidance on the presentation of deferred taxes. The Company elected to adopt the accounting change using the prospective method. See Note 2 of Notes to the Consolidated Financial Statements.
|
|
December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016(1)
|
|
2015(1)
|
|
2014(1)
|
||||||||||
|
(In thousands)
|
||||||||||||||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Operating activities
|
$
|
260,491
|
|
|
$
|
236,617
|
|
|
$
|
52,077
|
|
|
$
|
440,779
|
|
|
$
|
443,586
|
|
Investing activities
|
(985,138
|
)
|
|
(152,565
|
)
|
|
(537,763
|
)
|
|
(796,433
|
)
|
|
(368,603
|
)
|
|||||
Financing activities
|
605,277
|
|
|
(52,261
|
)
|
|
448,019
|
|
|
79,634
|
|
|
(139,184
|
)
|
(1)
|
Effective December 31, 2016, the Company adopted new guidance on the presentation of restricted cash. This guidance was adopted retrospectively and all prior periods have been adjusted to reflect this change in accounting principle.
|
|
Year Ended December 31, 2018
|
||||||||||
|
Kosmos
|
|
Equity Method Investment-Equatorial Guinea(1)
|
|
Total
|
||||||
|
(In thousands, except per volume data)
|
||||||||||
Sales volumes:
|
|
|
|
|
|
||||||
Oil (MBbl)
|
12,673
|
|
|
5,228
|
|
|
17,901
|
|
|||
Gas (MMcf)
|
2,268
|
|
|
—
|
|
|
2,268
|
|
|||
NGL (MBbl)
|
179
|
|
|
—
|
|
|
179
|
|
|||
Total (MBoe)
|
13,230
|
|
|
5,228
|
|
|
18,458
|
|
|||
Revenues:
|
|
|
|
|
|
||||||
Oil sales
|
$
|
874,382
|
|
|
$
|
360,649
|
|
|
$
|
1,235,031
|
|
Average oil sales price per Bbl
|
69.00
|
|
|
68.98
|
|
|
68.99
|
|
|||
Gas sales
|
7,101
|
|
|
—
|
|
|
7,101
|
|
|||
Average gas sales price per Mcf
|
3.13
|
|
|
—
|
|
|
3.13
|
|
|||
NGL sales
|
5,183
|
|
|
—
|
|
|
5,183
|
|
|||
Average NGL sales price per Bbl
|
29.00
|
|
|
—
|
|
|
28.96
|
|
|||
|
|
|
|
|
|
||||||
Costs:
|
|
|
|
|
|
||||||
Oil and gas production, excluding workovers
|
$
|
217,818
|
|
|
$
|
73,843
|
|
|
$
|
291,661
|
|
Oil and gas production, workovers
|
6,909
|
|
|
—
|
|
|
6,909
|
|
|||
Total oil and gas production costs
|
$
|
224,727
|
|
|
$
|
73,843
|
|
|
$
|
298,570
|
|
|
|
|
|
|
|
||||||
Depletion and depreciation
|
$
|
329,835
|
|
|
$
|
134,983
|
|
|
$
|
464,818
|
|
|
|
|
|
|
|
||||||
Average cost per Boe:
|
|
|
|
|
|
||||||
Oil and gas production, excluding workovers
|
$
|
16.46
|
|
|
$
|
14.12
|
|
|
$
|
15.80
|
|
Oil and gas production, workovers
|
0.52
|
|
|
—
|
|
|
0.38
|
|
|||
Total oil and gas production costs
|
16.98
|
|
|
14.12
|
|
|
16.18
|
|
|||
|
|
|
|
|
|
||||||
Depletion and depreciation
|
24.93
|
|
|
25.82
|
|
|
25.18
|
|
|||
Oil and gas production cost and depletion and depreciation costs
|
$
|
41.91
|
|
|
$
|
39.94
|
|
|
$
|
41.36
|
|
(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 and depreciation. 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.
|
|
Year Ended December 31, 2017
|
||||||||||
|
Kosmos
|
|
Equity Method Investment-Equatorial Guinea(1)
|
|
Total
|
||||||
|
(In thousands, except per volume data)
|
||||||||||
Sales volumes:
|
|
|
|
|
|
||||||
Oil (MBbl)
|
10,761
|
|
|
405
|
|
|
11,166
|
|
|||
Gas (MMcf)
|
—
|
|
|
—
|
|
|
—
|
|
|||
NGL (MBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total (MBoe)
|
10,761
|
|
|
405
|
|
|
11,166
|
|
|||
Revenues:
|
|
|
|
|
|
||||||
Oil sales
|
$
|
578,139
|
|
|
$
|
27,307
|
|
|
$
|
605,446
|
|
Average oil sales price per Bbl
|
53.73
|
|
|
67.42
|
|
|
54.22
|
|
|||
|
|
|
|
|
|
||||||
Costs:
|
|
|
|
|
|
||||||
Oil and gas production, excluding workovers
|
$
|
121,429
|
|
|
$
|
7,755
|
|
|
$
|
129,184
|
|
Oil and gas production, workovers
|
5,421
|
|
|
—
|
|
|
5,421
|
|
|||
Total oil and gas production costs
|
$
|
126,850
|
|
|
$
|
7,755
|
|
|
$
|
134,605
|
|
|
|
|
|
|
|
||||||
Depletion and depreciation
|
$
|
255,203
|
|
|
$
|
11,181
|
|
|
$
|
266,384
|
|
|
|
|
|
|
|
||||||
Average cost per Boe:
|
|
|
|
|
|
||||||
Oil and gas production, excluding workovers
|
$
|
11.28
|
|
|
$
|
19.15
|
|
|
$
|
11.57
|
|
Oil and gas production, workovers
|
0.50
|
|
|
—
|
|
|
0.48
|
|
|||
Total oil and gas production costs
|
11.78
|
|
|
19.15
|
|
|
12.05
|
|
|||
|
|
|
|
|
|
||||||
Depletion and depreciation
|
23.72
|
|
|
27.61
|
|
|
23.86
|
|
|||
Oil and gas production cost and depletion and depreciation costs
|
$
|
35.50
|
|
|
$
|
46.76
|
|
|
$
|
35.91
|
|
(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 and depreciation. 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.
|
|
Year Ended December 31,
|
||
|
2016
|
||
|
(In thousands, except per volume data)
|
||
Sales volumes:
|
|
||
Oil (MBbl)
|
6,756
|
|
|
Gas (MMcf)
|
—
|
|
|
NGL (MBbl)
|
—
|
|
|
Total (MBoe)
|
6,756
|
|
|
Revenues:
|
|
||
Oil sales
|
$
|
310,377
|
|
Average oil sales price per Bbl
|
45.94
|
|
|
|
|
||
Costs:
|
|
||
Oil and gas production, excluding workovers
|
$
|
119,758
|
|
Oil and gas production, workovers
|
(391
|
)
|
|
Total oil and gas production costs
|
$
|
119,367
|
|
|
|
||
Depletion and depreciation
|
$
|
140,404
|
|
|
|
||
Average cost per Boe:
|
|
||
Oil and gas production, excluding workovers
|
$
|
17.73
|
|
Oil and gas production, workovers
|
(0.06
|
)
|
|
Total oil and gas production costs
|
17.67
|
|
|
|
|
||
Depletion and depreciation
|
20.78
|
|
|
Oil and gas production cost and depletion and depreciation costs
|
$
|
38.45
|
|
|
Years Ended
|
|
|
||||||||
|
December 31,
|
|
Increase
|
||||||||
|
2018
|
|
2017
|
|
(Decrease)
|
||||||
|
(In thousands)
|
||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|||
Oil and gas revenue
|
$
|
886,666
|
|
|
$
|
578,139
|
|
|
$
|
308,527
|
|
Gain on sale of assets
|
7,666
|
|
|
—
|
|
|
7,666
|
|
|||
Other income, net
|
8,037
|
|
|
58,697
|
|
|
(50,660
|
)
|
|||
Total revenues and other income
|
902,369
|
|
|
636,836
|
|
|
265,533
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|||
Oil and gas production
|
224,727
|
|
|
126,850
|
|
|
97,877
|
|
|||
Facilities insurance modifications, net
|
6,955
|
|
|
(820
|
)
|
|
7,775
|
|
|||
Exploration expenses
|
301,492
|
|
|
216,050
|
|
|
85,442
|
|
|||
General and administrative
|
99,856
|
|
|
68,302
|
|
|
31,554
|
|
|||
Depletion and depreciation
|
329,835
|
|
|
255,203
|
|
|
74,632
|
|
|||
Interest and other financing costs, net
|
101,176
|
|
|
77,595
|
|
|
23,581
|
|
|||
Derivatives, net
|
(31,430
|
)
|
|
59,968
|
|
|
(91,398
|
)
|
|||
(Gain) loss on equity method investments, net
|
(72,881
|
)
|
|
6,252
|
|
|
(79,133
|
)
|
|||
Other expenses, net
|
(6,501
|
)
|
|
5,291
|
|
|
(11,792
|
)
|
|||
Total costs and expenses
|
953,229
|
|
|
814,691
|
|
|
138,538
|
|
|||
Loss before income taxes
|
(50,860
|
)
|
|
(177,855
|
)
|
|
126,995
|
|
|||
Income tax expense
|
43,131
|
|
|
44,937
|
|
|
(1,806
|
)
|
|||
Net loss
|
$
|
(93,991
|
)
|
|
$
|
(222,792
|
)
|
|
$
|
128,801
|
|
|
Years Ended
|
|
|
||||||||
|
December 31,
|
|
Increase
|
||||||||
|
2017
|
|
2016
|
|
(Decrease)
|
||||||
|
(In thousands)
|
||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|||
Oil and gas revenue
|
$
|
578,139
|
|
|
$
|
310,377
|
|
|
$
|
267,762
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|||
Other income, net
|
58,697
|
|
|
74,978
|
|
|
(16,281
|
)
|
|||
Total revenues and other income
|
636,836
|
|
|
385,355
|
|
|
251,481
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|||
Oil and gas production
|
126,850
|
|
|
119,367
|
|
|
7,483
|
|
|||
Facilities insurance modifications, net
|
(820
|
)
|
|
14,961
|
|
|
(15,781
|
)
|
|||
Exploration expenses
|
216,050
|
|
|
202,280
|
|
|
13,770
|
|
|||
General and administrative
|
68,302
|
|
|
87,623
|
|
|
(19,321
|
)
|
|||
Depletion and depreciation
|
255,203
|
|
|
140,404
|
|
|
114,799
|
|
|||
Interest and other financing costs, net
|
77,595
|
|
|
44,147
|
|
|
33,448
|
|
|||
Derivatives, net
|
59,968
|
|
|
48,021
|
|
|
11,947
|
|
|||
Loss on equity method investments, net
|
6,252
|
|
|
—
|
|
|
6,252
|
|
|||
Other expenses, net
|
5,291
|
|
|
23,116
|
|
|
(17,825
|
)
|
|||
Total costs and expenses
|
814,691
|
|
|
679,919
|
|
|
134,772
|
|
|||
Loss before income taxes
|
(177,855
|
)
|
|
(294,564
|
)
|
|
116,709
|
|
|||
Income tax expense (benefit)
|
44,937
|
|
|
(10,784
|
)
|
|
55,721
|
|
|||
Net loss
|
$
|
(222,792
|
)
|
|
$
|
(283,780
|
)
|
|
$
|
60,988
|
|
|
Years Ended
|
||||||||||
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Sources of cash, cash equivalents and restricted cash:
|
|
|
|
|
|
|
|
|
|||
Net cash provided by operating activities
|
$
|
260,491
|
|
|
$
|
236,617
|
|
|
$
|
52,077
|
|
Return of investment from KTIPI
|
184,664
|
|
|
—
|
|
|
—
|
|
|||
Borrowings under long-term debt
|
1,175,000
|
|
|
200,000
|
|
|
450,000
|
|
|||
Proceeds on sale of assets
|
13,703
|
|
|
222,068
|
|
|
210
|
|
|||
|
1,633,858
|
|
|
658,685
|
|
|
502,287
|
|
|||
Uses of cash, cash equivalents and restricted cash:
|
|
|
|
|
|
|
|
|
|||
Oil and gas assets
|
213,806
|
|
|
140,495
|
|
|
535,975
|
|
|||
Other property
|
7,935
|
|
|
2,858
|
|
|
1,998
|
|
|||
Acquisition of oil and gas properties
|
961,764
|
|
|
—
|
|
|
—
|
|
|||
Equity method investment
|
—
|
|
|
231,280
|
|
|
—
|
|
|||
Payments on long-term debt
|
325,000
|
|
|
250,000
|
|
|
—
|
|
|||
Purchase of treasury stock
|
206,051
|
|
|
2,194
|
|
|
1,981
|
|
|||
Deferred financing costs
|
38,672
|
|
|
67
|
|
|
—
|
|
|||
|
1,753,228
|
|
|
626,894
|
|
|
539,954
|
|
|||
Increase (decrease) in cash, cash equivalents and restricted cash
|
$
|
(119,370
|
)
|
|
$
|
31,791
|
|
|
$
|
(37,667
|
)
|
|
December 31, 2018
|
||
|
(In thousands)
|
||
Cash and cash equivalents
|
$
|
173,515
|
|
Restricted cash
|
12,101
|
|
|
Senior Notes at par
|
525,000
|
|
|
Drawings under the Facility
|
1,325,000
|
|
|
Drawings under the Corporate Revolver
|
325,000
|
|
|
Net debt
|
$
|
1,989,384
|
|
|
|
||
Availability under the Facility(1)
|
$
|
375,000
|
|
Availability under the Corporate Revolver
|
$
|
75,000
|
|
Available borrowings plus cash and cash equivalents
|
$
|
623,515
|
|
(1)
|
Includes letter agreements with existing financial institutions, entered into December 2018, which obligated the financial institutions to provide the Company with an additional commitment of $100 million in the aggregate under the Facility effective January 31, 2019.
|
•
|
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
|
•
|
Approximately 64% related to exploitation and production optimization activities across our Ghana, Equatorial Guinea and Gulf of Mexico assets
|
•
|
Approximately 19% related to our infrastructure-led exploration and development activities across Equatorial Guinea and the U.S. Gulf of Mexico
|
•
|
Approximately 2% related to the development of our world-scale discoveries in Mauritania and Senegal
|
•
|
Approximately 15% related to basin opening exploration efforts across our portfolio
|
•
|
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.
|
Year
|
|
Percentage
|
|
On or after August 1, 2018, but before August 1, 2019
|
|
102.0
|
%
|
On or after August 1, 2019 and thereafter
|
|
100.0
|
%
|
|
Payments Due By Year(4)
|
||||||||||||||||||||||||||
|
Total
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
||||||||||||||
Principal debt repayments(1)
|
$
|
2,175,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
685,600
|
|
|
$
|
614,100
|
|
|
$
|
305,100
|
|
|
$
|
570,200
|
|
Interest payments on long-term debt(2)
|
593,217
|
|
|
147,936
|
|
|
145,347
|
|
|
137,715
|
|
|
73,236
|
|
|
47,528
|
|
|
41,455
|
|
|||||||
Operating leases(3)
|
36,508
|
|
|
2,775
|
|
|
4,173
|
|
|
3,276
|
|
|
3,326
|
|
|
3,376
|
|
|
19,582
|
|
(1)
|
Includes the scheduled principal maturities for the
$525.0 million
aggregate principal amount of Senior Notes issued in August 2014 and April 2015, borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of
December 31, 2018
, 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.
|
|
Years Ending December 31,
|
|
Asset
(Liability)
Fair Value at
December 31,
|
||||||||||||||||||||||||
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
2018
|
||||||||||||||
|
(In thousands, except percentages)
|
||||||||||||||||||||||||||
Fixed rate debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Senior Notes
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
525,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(525,026
|
)
|
Fixed interest rate
|
7.88
|
%
|
|
7.88
|
%
|
|
7.88
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|||||||
Variable rate debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Facility(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
160,600
|
|
|
$
|
289,100
|
|
|
$
|
305,100
|
|
|
$
|
570,200
|
|
|
$
|
(1,325,000
|
)
|
Corporate Revolver
|
—
|
|
|
—
|
|
|
—
|
|
|
325,000
|
|
|
—
|
|
|
—
|
|
|
(325,000
|
)
|
|||||||
Weighted average interest rate(2)
|
6.14
|
%
|
|
5.99
|
%
|
|
5.97
|
%
|
|
6.03
|
%
|
|
6.14
|
%
|
|
6.82
|
%
|
|
|
|
(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, 2018
. 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.
|
•
|
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.
|
•
|
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.
|
|
Derivative Contracts Assets (Liabilities)
|
||||||||||
|
Commodities
|
|
Interest Rates
|
|
Total
|
||||||
|
(In thousands)
|
||||||||||
Fair value of contracts outstanding as of December 31, 2017
|
$
|
(97,036
|
)
|
|
$
|
1,017
|
|
|
$
|
(96,019
|
)
|
Acquisition and novation of DGE contracts
|
(41,139
|
)
|
|
—
|
|
|
$
|
(41,139
|
)
|
||
Changes in contract fair value
|
29,468
|
|
|
492
|
|
|
29,960
|
|
|||
Contract maturities
|
139,451
|
|
|
(1,509
|
)
|
|
137,942
|
|
|||
Fair value of contracts outstanding as of December 31, 2018
|
$
|
30,744
|
|
|
$
|
—
|
|
|
$
|
30,744
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per Bbl
|
|
Asset (Liability)
|
|||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value at
December 31,
|
|||||||||||||
Term
|
|
Type of Contract
|
|
Index
|
|
MBbl
|
|
Net Deferred Premium Payable/(Receivable)
|
|
Swap
|
|
Sold Put
|
|
Floor
|
|
Ceiling
|
|
2018(3)
|
|||||||||||||
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
January — December
|
|
Three-way collars
|
|
Dated Brent
|
|
10,500
|
|
|
$
|
1.17
|
|
|
$
|
—
|
|
|
$
|
43.81
|
|
|
$
|
53.33
|
|
|
$
|
73.58
|
|
|
$
|
13,355
|
|
January — December
|
|
Sold calls(1)
|
|
Dated Brent
|
|
913
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
80.00
|
|
|
(9,465
|
)
|
||||||
January — December
|
|
Swaps
|
|
NYMEX WTI
|
|
1,747
|
|
|
—
|
|
|
52.31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,988
|
|
||||||
January — June
|
|
Collars
|
|
NYMEX WTI
|
|
339
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57.77
|
|
|
63.70
|
|
|
3,968
|
|
||||||
January — December
|
|
Collars
|
|
Argus LLS
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60.00
|
|
|
88.75
|
|
|
10,390
|
|
||||||
2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
January — December
|
|
Three-way collars
|
|
Dated Brent
|
|
2,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
50.00
|
|
|
$
|
60.00
|
|
|
$
|
90.54
|
|
|
$
|
9,181
|
|
January — December
|
|
Sold calls(1)(2)
|
|
Dated Brent
|
|
8,000
|
|
|
1.17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
85.00
|
|
|
(6,108
|
)
|
(1)
|
Represents call option contracts sold to counterparties to enhance other derivative positions.
|
(2)
|
Deferred premium payable to be paid January - December 2019.
|
(3)
|
Fair values are based on the average forward oil prices on
December 31, 2018
.
|
|
Page
|
Consolidated Financial Statements of Kosmos Energy Ltd.:
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Assets
|
|
|
|
|
|
||
Current assets:
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
173,515
|
|
|
$
|
233,412
|
|
Restricted cash
|
4,527
|
|
|
56,380
|
|
||
Receivables:
|
|
|
|
|
|
||
Joint interest billings, net
|
64,572
|
|
|
134,565
|
|
||
Oil sales
|
48,164
|
|
|
—
|
|
||
Related party
|
5,580
|
|
|
780
|
|
||
Other
|
21,690
|
|
|
25,616
|
|
||
Inventories
|
84,827
|
|
|
71,861
|
|
||
Prepaid expenses and other
|
68,040
|
|
|
9,306
|
|
||
Derivatives
|
38,785
|
|
|
1,682
|
|
||
Total current assets
|
509,700
|
|
|
533,602
|
|
||
|
|
|
|
||||
Property and equipment:
|
|
|
|
|
|
||
Oil and gas properties, net
|
3,444,864
|
|
|
2,310,973
|
|
||
Other property, net
|
14,837
|
|
|
6,855
|
|
||
Property and equipment, net
|
3,459,701
|
|
|
2,317,828
|
|
||
|
|
|
|
||||
Other assets:
|
|
|
|
|
|
||
Equity method investment
|
51,896
|
|
|
236,514
|
|
||
Restricted cash
|
7,574
|
|
|
15,194
|
|
||
Long-term receivables - joint interest billings
|
19,002
|
|
|
34,941
|
|
||
Deferred financing costs, net of accumulated amortization of $12,065 and $13,951 at December 31, 2018 and December 31, 2017, respectively
|
8,937
|
|
|
2,510
|
|
||
Deferred tax assets
|
14,004
|
|
|
22,517
|
|
||
Derivatives
|
14,312
|
|
|
39
|
|
||
Other
|
3,063
|
|
|
29,458
|
|
||
Total assets
|
$
|
4,088,189
|
|
|
$
|
3,192,603
|
|
|
|
|
|
||||
Liabilities and shareholders’ equity
|
|
|
|
|
|
||
Current liabilities:
|
|
|
|
|
|
||
Accounts payable
|
$
|
176,540
|
|
|
$
|
141,787
|
|
Accrued liabilities
|
195,596
|
|
|
219,412
|
|
||
Derivatives
|
12,172
|
|
|
67,531
|
|
||
Total current liabilities
|
384,308
|
|
|
428,730
|
|
||
|
|
|
|
||||
Long-term liabilities:
|
|
|
|
|
|
||
Long-term debt, net
|
2,120,547
|
|
|
1,282,797
|
|
||
Derivatives
|
10,181
|
|
|
30,209
|
|
||
Asset retirement obligations
|
145,336
|
|
|
66,595
|
|
||
Deferred tax liabilities
|
477,179
|
|
|
476,548
|
|
||
Other long-term liabilities
|
9,160
|
|
|
10,612
|
|
||
Total long-term liabilities
|
2,762,403
|
|
|
1,866,761
|
|
||
|
|
|
|
||||
Shareholders’ equity:
|
|
|
|
|
|
||
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2018 and December 31, 2017
|
—
|
|
|
—
|
|
||
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 442,914,675 and 398,599,457 issued at December 31, 2018 and December 31, 2017, respectively
|
4,429
|
|
|
3,986
|
|
||
Additional paid-in capital
|
2,341,249
|
|
|
2,014,525
|
|
||
Accumulated deficit
|
(1,167,193
|
)
|
|
(1,073,202
|
)
|
||
Treasury stock, at cost, 44,263,269 and 9,188,819 shares at December 31, 2018 and December 31, 2017, respectively
|
(237,007
|
)
|
|
(48,197
|
)
|
||
Total shareholders’ equity
|
941,478
|
|
|
897,112
|
|
||
Total liabilities and shareholders’ equity
|
$
|
4,088,189
|
|
|
$
|
3,192,603
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|||
Oil and gas revenue
|
$
|
886,666
|
|
|
$
|
578,139
|
|
|
$
|
310,377
|
|
Gain on sale of assets
|
7,666
|
|
|
—
|
|
|
—
|
|
|||
Other income, net
|
8,037
|
|
|
58,697
|
|
|
74,978
|
|
|||
|
|
|
|
|
|
||||||
Total revenues and other income
|
902,369
|
|
|
636,836
|
|
|
385,355
|
|
|||
|
|
|
|
|
|
||||||
Costs and expenses:
|
|
|
|
|
|
||||||
Oil and gas production
|
224,727
|
|
|
126,850
|
|
|
119,367
|
|
|||
Facilities insurance modifications, net
|
6,955
|
|
|
(820
|
)
|
|
14,961
|
|
|||
Exploration expenses
|
301,492
|
|
|
216,050
|
|
|
202,280
|
|
|||
General and administrative
|
99,856
|
|
|
68,302
|
|
|
87,623
|
|
|||
Depletion and depreciation
|
329,835
|
|
|
255,203
|
|
|
140,404
|
|
|||
Interest and other financing costs, net
|
101,176
|
|
|
77,595
|
|
|
44,147
|
|
|||
Derivatives, net
|
(31,430
|
)
|
|
59,968
|
|
|
48,021
|
|
|||
(Gain) loss on equity method investments, net
|
(72,881
|
)
|
|
6,252
|
|
|
—
|
|
|||
Other expenses, net
|
(6,501
|
)
|
|
5,291
|
|
|
23,116
|
|
|||
|
|
|
|
|
|
||||||
Total costs and expenses
|
953,229
|
|
|
814,691
|
|
|
679,919
|
|
|||
|
|
|
|
|
|
||||||
Loss before income taxes
|
(50,860
|
)
|
|
(177,855
|
)
|
|
(294,564
|
)
|
|||
Income tax expense (benefit)
|
43,131
|
|
|
44,937
|
|
|
(10,784
|
)
|
|||
|
|
|
|
|
|
||||||
Net loss
|
$
|
(93,991
|
)
|
|
$
|
(222,792
|
)
|
|
$
|
(283,780
|
)
|
Net loss per share:
|
|
|
|
|
|
|
|
|
|||
Basic
|
$
|
(0.23
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.74
|
)
|
Diluted
|
$
|
(0.23
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.74
|
)
|
Weighted average number of shares used to compute net loss per share:
|
|
|
|
|
|
|
|
|
|||
Basic
|
404,585
|
|
|
388,375
|
|
|
385,402
|
|
|||
Diluted
|
404,585
|
|
|
388,375
|
|
|
385,402
|
|
|
Common Stock
|
|
Additional Paid-in
|
|
Accumulated
|
|
Treasury
|
|
|
|||||||||||||
|
Shares
|
|
Amount
|
|
Capital
|
|
Deficit
|
|
Stock
|
|
Total
|
|||||||||||
Balance as of December 31, 2015
|
393,903
|
|
|
$
|
3,939
|
|
|
$
|
1,933,189
|
|
|
$
|
(564,686
|
)
|
|
$
|
(46,929
|
)
|
|
$
|
1,325,513
|
|
Equity-based compensation
|
—
|
|
|
—
|
|
|
43,391
|
|
|
(1,944
|
)
|
|
—
|
|
|
41,447
|
|
|||||
Restricted stock awards and units
|
1,956
|
|
|
20
|
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Restricted stock forfeitures
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
(1,315
|
)
|
|
—
|
|
|
(666
|
)
|
|
(1,981
|
)
|
|||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(283,780
|
)
|
|
—
|
|
|
(283,780
|
)
|
|||||
Balance as of December 31, 2016
|
395,859
|
|
|
3,959
|
|
|
1,975,247
|
|
|
(850,410
|
)
|
|
(47,597
|
)
|
|
1,081,199
|
|
|||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
40,899
|
|
|
—
|
|
|
—
|
|
|
40,899
|
|
|||||
Restricted stock awards and units
|
2,740
|
|
|
27
|
|
|
(27
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
(1,594
|
)
|
|
—
|
|
|
(600
|
)
|
|
(2,194
|
)
|
|||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(222,792
|
)
|
|
—
|
|
|
(222,792
|
)
|
|||||
Balance as of December 31, 2017
|
398,599
|
|
|
3,986
|
|
|
2,014,525
|
|
|
(1,073,202
|
)
|
|
(48,197
|
)
|
|
897,112
|
|
|||||
Acquisition of oil and gas properties
|
34,994
|
|
|
350
|
|
|
307,594
|
|
|
—
|
|
|
—
|
|
|
307,944
|
|
|||||
Equity-based compensation
|
—
|
|
|
—
|
|
|
36,464
|
|
|
—
|
|
|
—
|
|
|
36,464
|
|
|||||
Restricted stock awards and units
|
9,322
|
|
|
93
|
|
|
(93
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
(17,241
|
)
|
|
—
|
|
|
(188,810
|
)
|
|
(206,051
|
)
|
|||||
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
(93,991
|
)
|
|
—
|
|
|
(93,991
|
)
|
|||||
Balance as of December 31, 2018
|
442,915
|
|
|
$
|
4,429
|
|
|
$
|
2,341,249
|
|
|
$
|
(1,167,193
|
)
|
|
$
|
(237,007
|
)
|
|
$
|
941,478
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Operating activities
|
|
|
|
|
|
|
|
|
|||
Net loss
|
$
|
(93,991
|
)
|
|
$
|
(222,792
|
)
|
|
$
|
(283,780
|
)
|
Adjustments to reconcile net loss to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depletion, depreciation and amortization
|
339,214
|
|
|
265,407
|
|
|
150,608
|
|
|||
Deferred income taxes
|
9,145
|
|
|
9,505
|
|
|
(23,561
|
)
|
|||
Unsuccessful well costs
|
123,199
|
|
|
43,201
|
|
|
6,079
|
|
|||
Change in fair value of derivatives
|
(29,960
|
)
|
|
71,822
|
|
|
46,559
|
|
|||
Cash settlements on derivatives, net (including $(137.1) million and $38.7 million and $188.0 million on commodity hedges during 2018, 2017, and 2016)
|
(137,942
|
)
|
|
25,888
|
|
|
188,895
|
|
|||
Equity-based compensation
|
35,230
|
|
|
39,913
|
|
|
40,084
|
|
|||
Gain on sale of assets
|
(7,666
|
)
|
|
—
|
|
|
—
|
|
|||
Loss on extinguishment of debt
|
4,324
|
|
|
—
|
|
|
—
|
|
|||
Loss on equity method investment, net / (Undistributed equity in earnings)
|
(45
|
)
|
|
6,252
|
|
|
—
|
|
|||
Other
|
2,865
|
|
|
5,952
|
|
|
13,355
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
(Increase) decrease in receivables
|
175,954
|
|
|
29,365
|
|
|
(20,558
|
)
|
|||
(Increase) decrease in inventories
|
8,848
|
|
|
1,653
|
|
|
(4,107
|
)
|
|||
(Increase) decrease in prepaid expenses and other
|
(18,731
|
)
|
|
(31,710
|
)
|
|
17,557
|
|
|||
Increase (decrease) in accounts payable
|
7,440
|
|
|
(94,434
|
)
|
|
(75,487
|
)
|
|||
Increase (decrease) in accrued liabilities
|
(157,393
|
)
|
|
86,595
|
|
|
(3,567
|
)
|
|||
Net cash provided by operating activities
|
260,491
|
|
|
236,617
|
|
|
52,077
|
|
|||
|
|
|
|
|
|
||||||
Investing activities
|
|
|
|
|
|
||||||
Oil and gas assets
|
(213,806
|
)
|
|
(140,495
|
)
|
|
(535,975
|
)
|
|||
Other property
|
(7,935
|
)
|
|
(2,858
|
)
|
|
(1,998
|
)
|
|||
Acquisition of oil and gas properties, net of cash acquired
|
(961,764
|
)
|
|
—
|
|
|
—
|
|
|||
Equity method investment
|
—
|
|
|
(231,280
|
)
|
|
—
|
|
|||
Return of investment from KTIPI
|
184,664
|
|
|
—
|
|
|
—
|
|
|||
Proceeds on sale of assets
|
13,703
|
|
|
222,068
|
|
|
210
|
|
|||
Net cash used in investing activities
|
(985,138
|
)
|
|
(152,565
|
)
|
|
(537,763
|
)
|
|||
|
|
|
|
|
|
||||||
Financing activities
|
|
|
|
|
|
||||||
Borrowings under long-term debt
|
1,175,000
|
|
|
200,000
|
|
|
450,000
|
|
|||
Payments on long-term debt
|
(325,000
|
)
|
|
(250,000
|
)
|
|
—
|
|
|||
Purchase of treasury stock / tax withholdings
|
(206,051
|
)
|
|
(2,194
|
)
|
|
(1,981
|
)
|
|||
Deferred financing costs
|
(38,672
|
)
|
|
(67
|
)
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
605,277
|
|
|
(52,261
|
)
|
|
448,019
|
|
|||
|
|
|
|
|
|
||||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
(119,370
|
)
|
|
31,791
|
|
|
(37,667
|
)
|
|||
Cash, cash equivalents and restricted cash at beginning of period
|
304,986
|
|
|
273,195
|
|
|
310,862
|
|
|||
Cash, cash equivalents and restricted cash at end of period
|
$
|
185,616
|
|
|
$
|
304,986
|
|
|
$
|
273,195
|
|
|
|
|
|
|
|
||||||
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
|||
Cash paid for:
|
|
|
|
|
|
|
|
|
|||
Interest, net of capitalized interest
|
$
|
83,831
|
|
|
$
|
55,381
|
|
|
$
|
27,860
|
|
Income taxes
|
$
|
45,984
|
|
|
$
|
48,815
|
|
|
$
|
13,997
|
|
|
|
|
|
|
|
||||||
Non-cash activity:
|
|
|
|
|
|
||||||
Conversion of joint interest billings receivable to long-term note receivable
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,814
|
|
Contribution to equity method investment
|
$
|
—
|
|
|
$
|
133,893
|
|
|
$
|
—
|
|
Dissolution of equity method investment
|
$
|
—
|
|
|
$
|
(122,407
|
)
|
|
$
|
—
|
|
Common stock issued for acquisition of oil and gas properties
|
$
|
307,944
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Cash and cash equivalents
|
$
|
173,515
|
|
|
$
|
233,412
|
|
|
$
|
194,057
|
|
Restricted cash - current
|
4,527
|
|
|
56,380
|
|
|
24,506
|
|
|||
Restricted cash - long-term
|
7,574
|
|
|
15,194
|
|
|
54,632
|
|
|||
Total cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows
|
$
|
185,616
|
|
|
$
|
304,986
|
|
|
$
|
273,195
|
|
|
Years
Depreciated
|
Leasehold improvements
|
1 to 8
|
Office furniture, fixtures and computer equipment
|
3 to 7
|
Vehicles
|
5
|
•
|
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.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
|
||||||||||
Revenues from contracts with customers - Ghana
|
$
|
741,033
|
|
|
$
|
590,642
|
|
|
$
|
307,837
|
|
Revenues from contracts with customers - U.S. Gulf of Mexico
|
147,596
|
|
|
—
|
|
|
—
|
|
|||
Provisional oil sales contracts
|
(1,963
|
)
|
|
(12,503
|
)
|
|
2,540
|
|
|||
Oil and gas revenue
|
$
|
886,666
|
|
|
$
|
578,139
|
|
|
$
|
310,377
|
|
|
|
Purchase Price Allocation
(in thousands)
|
||
Fair value of assets acquired:
|
|
|
||
Proved oil and gas properties
|
|
$
|
1,037,511
|
|
Unproved oil and gas properties
|
|
298,159
|
|
|
Accounts receivable and other
|
|
180,989
|
|
|
Total assets acquired
|
|
$
|
1,516,659
|
|
|
|
|
||
Fair value of liabilities assumed:
|
|
|
||
Accrued liabilities and other
|
|
$
|
126,530
|
|
Asset retirement obligations
|
|
74,482
|
|
|
Derivative liabilities
|
|
40,265
|
|
|
Total liabilities assumed
|
|
$
|
241,277
|
|
|
|
|
||
Purchase price:
|
|
|
||
Cash consideration paid
|
|
$
|
952,586
|
|
Fair value of common stock(1)
|
|
307,944
|
|
|
Transaction related costs
|
|
14,852
|
|
|
Total purchase price
|
|
$
|
1,275,382
|
|
(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.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Oil and gas properties:
|
|
|
|
|
|
||
Proved properties
|
$
|
2,773,276
|
|
|
$
|
1,653,616
|
|
Unproved properties
|
759,472
|
|
|
465,109
|
|
||
Support equipment and facilities
|
1,463,213
|
|
|
1,427,054
|
|
||
Total oil and gas properties
|
4,995,961
|
|
|
3,545,779
|
|
||
Accumulated depletion
|
(1,551,097
|
)
|
|
(1,234,806
|
)
|
||
Oil and gas properties, net
|
3,444,864
|
|
|
2,310,973
|
|
||
|
|
|
|
||||
Other property
|
51,987
|
|
|
39,405
|
|
||
Accumulated depreciation
|
(37,150
|
)
|
|
(32,550
|
)
|
||
Other property, net
|
14,837
|
|
|
6,855
|
|
||
|
|
|
|
||||
Property and equipment, net
|
$
|
3,459,701
|
|
|
$
|
2,317,828
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Beginning balance
|
$
|
410,113
|
|
|
$
|
734,463
|
|
|
$
|
426,881
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
10,518
|
|
|
69,567
|
|
|
307,582
|
|
|||
Additions associated with the acquisition of DGE
|
26,224
|
|
|
—
|
|
|
—
|
|
|||
Reclassification due to determination of proved reserves(1)
|
(26,224
|
)
|
|
(176,881
|
)
|
|
—
|
|
|||
Divestitures(2)
|
—
|
|
|
(206,400
|
)
|
|
—
|
|
|||
Contribution of oil and gas property to equity method investment - KBSL
|
—
|
|
|
(131,764
|
)
|
|
—
|
|
|||
Dissolution of equity method investment - KBSL
|
—
|
|
|
121,128
|
|
|
—
|
|
|||
Capitalized exploratory well costs charged to expense(3)
|
(52,966
|
)
|
|
—
|
|
|
—
|
|
|||
Ending balance
|
$
|
367,665
|
|
|
$
|
410,113
|
|
|
$
|
734,463
|
|
(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 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.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands, except well counts)
|
||||||||||
Exploratory well costs capitalized for a period of one year or less
|
$
|
—
|
|
|
$
|
67,159
|
|
|
$
|
279,809
|
|
Exploratory well costs capitalized for a period of one to two years
|
299,253
|
|
|
291,252
|
|
|
244,804
|
|
|||
Exploratory well costs capitalized for a period of three years or longer
|
68,412
|
|
|
51,702
|
|
|
209,850
|
|
|||
Ending balance
|
$
|
367,665
|
|
|
$
|
410,113
|
|
|
$
|
734,463
|
|
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
|
3
|
|
|
5
|
|
|
5
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Assets
|
|
|
|
|
|||
Total current assets
|
$
|
149,950
|
|
|
$
|
179,070
|
|
Property and equipment, net
|
271,627
|
|
|
345,611
|
|
||
Other assets
|
21
|
|
|
567
|
|
||
Total assets
|
$
|
421,598
|
|
|
$
|
525,248
|
|
|
|
|
|
||||
Liabilities and shareholders' deficit
|
|
|
|
||||
Total current liabilities
|
$
|
226,311
|
|
|
$
|
106,769
|
|
Total long term liabilities
|
536,178
|
|
|
565,591
|
|
||
Shareholders' deficit:
|
|
|
|
||||
Total shareholders' deficit
|
(340,891
|
)
|
|
(147,112
|
)
|
||
Total liabilities and shareholders' deficit
|
$
|
421,598
|
|
|
$
|
525,248
|
|
|
Year Ended December 31, 2018
|
|
Period
November 28, 2017 through
December 31, 2017
|
||||
|
(In thousands)
|
||||||
Revenues and other income:
|
|
|
|
|
|||
Oil and gas revenue
|
$
|
721,299
|
|
|
$
|
54,615
|
|
Other income
|
(477
|
)
|
|
294
|
|
||
Total revenues and other income
|
720,822
|
|
|
54,909
|
|
||
|
|
|
|
||||
Costs and expenses:
|
|
|
|
||||
Oil and gas production
|
147,685
|
|
|
15,509
|
|
||
Depletion and depreciation
|
126,983
|
|
|
10,738
|
|
||
Other expenses, net
|
429
|
|
|
(19
|
)
|
||
Total costs and expenses
|
275,097
|
|
|
26,228
|
|
||
|
|
|
|
||||
Income before income taxes
|
445,725
|
|
|
28,681
|
|
||
Income tax expense
|
156,981
|
|
|
6,588
|
|
||
Net income
|
$
|
288,744
|
|
|
$
|
22,093
|
|
|
|
|
|
||||
Kosmos' share of net income
|
$
|
144,372
|
|
|
$
|
11,046
|
|
Basis difference amortization(1)
|
71,491
|
|
|
5,812
|
|
||
Equity in earnings - KTIPI
|
$
|
72,881
|
|
|
$
|
5,234
|
|
(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.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Outstanding debt principal balances:
|
|
|
|
|
|
||
Facility
|
$
|
1,325,000
|
|
|
$
|
800,000
|
|
Corporate Revolver
|
325,000
|
|
|
—
|
|
||
Senior Notes
|
525,000
|
|
|
525,000
|
|
||
Total
|
2,175,000
|
|
|
1,325,000
|
|
||
Unamortized deferred financing costs and discounts(1)
|
(54,453
|
)
|
|
(42,203
|
)
|
||
Long-term debt, net
|
$
|
2,120,547
|
|
|
$
|
1,282,797
|
|
(1)
|
Includes
$40.5 million
and
$23.6 million
of unamortized deferred financing costs related to the Facility and
$14.0 million
and
$18.6 million
of unamortized deferred financing costs and discounts related to the Senior Notes as of December 31,
2018
and December 31,
2017
, respectively.
|
Year
|
|
Percentage
|
|
On or after August 1, 2018, but before August 1, 2019
|
|
102.0
|
%
|
On or after August 1, 2019 and thereafter
|
|
100.0
|
%
|
|
Payments Due by Year
|
||||||||||||||||||||||||||
|
Total
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||
Principal debt repayments(1)
|
$
|
2,175,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
685,600
|
|
|
$
|
614,100
|
|
|
$
|
305,100
|
|
|
$
|
570,200
|
|
(1)
|
Includes the scheduled principal maturities for the
$525.0 million
aggregate principal amount of Senior Notes issued in August 2014 and April 2015, borrowings under the Facility and the Corporate Revolver. The scheduled maturities of debt related to the Facility are based on, as of
December 31, 2018
, 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.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Interest expense
|
$
|
114,134
|
|
|
$
|
92,687
|
|
|
$
|
89,029
|
|
Amortization—deferred financing costs
|
9,379
|
|
|
10,204
|
|
|
10,204
|
|
|||
Loss on extinguishment of debt
|
4,324
|
|
|
—
|
|
|
—
|
|
|||
Capitalized interest
|
(28,331
|
)
|
|
(30,282
|
)
|
|
(59,803
|
)
|
|||
Deferred interest
|
(1,138
|
)
|
|
2,577
|
|
|
(581
|
)
|
|||
Interest income
|
(3,455
|
)
|
|
(3,422
|
)
|
|
(1,954
|
)
|
|||
Other, net
|
6,263
|
|
|
5,831
|
|
|
7,252
|
|
|||
Interest and other financing costs, net
|
$
|
101,176
|
|
|
$
|
77,595
|
|
|
$
|
44,147
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per Bbl
|
|||||||||||||||||||
Term
|
|
Type of Contract
|
|
Index
|
|
MBbl
|
|
Net Deferred Premium Payable/(Receivable)
|
|
Swap
|
|
Sold Put
|
|
Floor
|
|
Ceiling
|
|||||||||||
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
January — December
|
|
Three-way collars
|
|
Dated Brent
|
|
10,500
|
|
|
$
|
1.17
|
|
|
$
|
—
|
|
|
$
|
43.81
|
|
|
$
|
53.33
|
|
|
$
|
73.58
|
|
January — December
|
|
Sold calls(1)
|
|
Dated Brent
|
|
913
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
80.00
|
|
|||||
January — December
|
|
Swaps
|
|
NYMEX WTI
|
|
1,747
|
|
|
—
|
|
|
52.31
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
January — June
|
|
Collars
|
|
NYMEX WTI
|
|
339
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57.77
|
|
|
63.70
|
|
|||||
January — December
|
|
Collars
|
|
Argus LLS
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60.00
|
|
|
88.75
|
|
|||||
2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
January — December
|
|
Three-way collars
|
|
Dated Brent
|
|
2,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
50.00
|
|
|
$
|
60.00
|
|
|
$
|
90.54
|
|
January — December
|
|
Sold calls(1)(2)
|
|
Dated Brent
|
|
8,000
|
|
|
1.17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
85.00
|
|
(1)
|
Represents call option contracts sold to counterparties to enhance other derivative positions.
|
(2)
|
Deferred premium payable to be paid January - December 2019.
|
|
|
|
|
Estimated Fair Value Asset (Liability)
|
||||||
|
|
|
|
December 31,
|
||||||
Type of Contract
|
|
Balance Sheet Location
|
|
2018
|
|
2017
|
||||
|
|
|
|
(In thousands)
|
||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
||||
Derivative assets:
|
|
|
|
|
|
|
||||
Commodity(1)
|
|
Derivatives assets—current
|
|
$
|
38,785
|
|
|
$
|
665
|
|
Interest rate
|
|
Derivatives assets—current
|
|
—
|
|
|
1,017
|
|
||
Commodity(2)
|
|
Derivatives assets—long-term
|
|
14,312
|
|
|
39
|
|
||
Derivative liabilities:
|
|
|
|
|
|
|
||||
Commodity(3)
|
|
Derivatives liabilities—current
|
|
(12,172
|
)
|
|
(67,531
|
)
|
||
Commodity(4)
|
|
Derivatives liabilities—long-term
|
|
(10,181
|
)
|
|
(30,209
|
)
|
||
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
30,744
|
|
|
$
|
(96,019
|
)
|
(1)
|
Includes
$0.4
million and
zero
as of December 31, 2018 and December 31, 2017, respectively which represents our provisional oil sales contract. Also, includes net deferred premiums payable of
$1.6 million
and net deferred premiums receivable of
$0.8 million
related to commodity derivative contracts as of December 31,
2018
and
2017
, respectively.
|
(2)
|
Includes net deferred premiums payable of
$1.3 million
and net deferred premiums receivable of
$0.1 million
related to commodity derivative contracts as of December 31,
2018
and
2017
, respectively.
|
(3)
|
Includes net deferred premiums payable of
$18.0 million
and
$5.6 million
related to commodity derivative contracts as of December 31,
2018
and
2017
, respectively.
|
(4)
|
Includes net deferred premiums payable of
$0.5 million
and
$4.8 million
related to commodity derivative contracts as of December 31,
2018
and
2017
, respectively.
|
|
|
|
|
Amount of Gain/(Loss)
|
||||||||||
|
|
|
|
Years Ended December 31,
|
||||||||||
Type of Contract
|
|
Location of Gain/(Loss)
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
|
|
|
(In thousands)
|
||||||||||
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Commodity(1)
|
|
Oil and gas revenue
|
|
$
|
(1,963
|
)
|
|
$
|
(12,502
|
)
|
|
$
|
2,538
|
|
Commodity
|
|
Derivatives, net
|
|
31,430
|
|
|
(59,968
|
)
|
|
(48,021
|
)
|
|||
Interest rate
|
|
Interest expense
|
|
493
|
|
|
648
|
|
|
(1,076
|
)
|
|||
Total derivatives not designated as hedging instruments
|
|
|
|
$
|
29,960
|
|
|
$
|
(71,822
|
)
|
|
$
|
(46,559
|
)
|
(1)
|
Amounts represent the change in fair value of our provisional oil sales contracts.
|
•
|
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.
|
|
Fair Value Measurements Using:
|
||||||||||||||
|
Quoted Prices in Active Markets for Identical Assets
|
|
Significant Other
Observable Inputs
|
|
Significant Unobservable Inputs
|
|
|
||||||||
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Total
|
||||||||
|
(In thousands)
|
||||||||||||||
December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commodity derivatives
|
$
|
—
|
|
|
$
|
53,097
|
|
|
$
|
—
|
|
|
$
|
53,097
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commodity derivatives
|
—
|
|
|
(22,353
|
)
|
|
—
|
|
|
(22,353
|
)
|
||||
Total
|
$
|
—
|
|
|
$
|
30,744
|
|
|
$
|
—
|
|
|
$
|
30,744
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|||||||
Assets:
|
|
|
|
|
|
|
|
|
|||||||
Commodity derivatives
|
$
|
—
|
|
|
$
|
704
|
|
|
$
|
—
|
|
|
$
|
704
|
|
Interest rate derivatives
|
—
|
|
|
1,017
|
|
|
—
|
|
|
1,017
|
|
||||
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Commodity derivatives
|
—
|
|
|
(97,740
|
)
|
|
—
|
|
|
(97,740
|
)
|
||||
Total
|
$
|
—
|
|
|
$
|
(96,019
|
)
|
|
$
|
—
|
|
|
$
|
(96,019
|
)
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
||||||||
|
(In thousands)
|
||||||||||||||
Senior Notes
|
$
|
511,873
|
|
|
$
|
525,026
|
|
|
$
|
507,600
|
|
|
$
|
542,472
|
|
Corporate Revolver
|
325,000
|
|
|
325,000
|
|
|
—
|
|
|
—
|
|
||||
Facility
|
1,325,000
|
|
|
1,325,000
|
|
|
800,000
|
|
|
800,000
|
|
||||
Total
|
$
|
2,161,873
|
|
|
$
|
2,175,026
|
|
|
$
|
1,307,600
|
|
|
$
|
1,342,472
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Asset retirement obligations:
|
|
|
|
|
|
||
Beginning asset retirement obligations
|
$
|
66,595
|
|
|
$
|
63,574
|
|
Additions associated with the acquisition of DGE
|
74,482
|
|
|
—
|
|
||
Liabilities incurred during period
|
5,311
|
|
|
—
|
|
||
Liabilities settled during period
|
(3,345
|
)
|
|
—
|
|
||
Revisions in estimated retirement obligations
|
—
|
|
|
(3,945
|
)
|
||
Accretion expense
|
8,910
|
|
|
6,966
|
|
||
Ending asset retirement obligations
|
$
|
151,953
|
|
|
$
|
66,595
|
|
|
Service Vesting Restricted Stock Awards
|
|
Weighted- Average Grant-Date Fair Value
|
|
Market / Service Vesting Restricted Stock Awards
|
|
Weighted- Average Grant-Date Fair Value
|
||||||
|
(In thousands)
|
|
|
|
(In thousands)
|
|
|
||||||
Outstanding at December 31, 2015:
|
810
|
|
|
$
|
9.20
|
|
|
261
|
|
|
$
|
9.44
|
|
Granted
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
—
|
|
|
—
|
|
|
(162
|
)
|
|
9.44
|
|
||
Vested
|
(322
|
)
|
|
9.77
|
|
|
(99
|
)
|
|
9.44
|
|
||
Outstanding at December 31, 2016:
|
488
|
|
|
8.83
|
|
|
—
|
|
|
—
|
|
||
Granted
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Vested
|
(268
|
)
|
|
8.97
|
|
|
—
|
|
|
—
|
|
||
Outstanding at December 31, 2017:
|
220
|
|
|
8.64
|
|
|
—
|
|
|
—
|
|
||
Granted
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Forfeited
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Vested
|
(220
|
)
|
|
8.64
|
|
|
—
|
|
|
—
|
|
||
Outstanding at December 31, 2018:
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Service Vesting
Restricted Stock
Units
|
|
Weighted- Average Grant-Date Fair Value
|
|
Market / Service Vesting Restricted Stock Units
|
|
Weighted-Average Grant-Date Fair Value
|
||||||
|
(In thousands)
|
|
|
|
(In thousands)
|
|
|
||||||
Outstanding at December 31, 2015:
|
3,592
|
|
|
$
|
9.79
|
|
|
6,578
|
|
|
$
|
14.24
|
|
Granted
|
2,158
|
|
|
4.05
|
|
|
1,379
|
|
|
4.88
|
|
||
Forfeited
|
(134
|
)
|
|
8.87
|
|
|
(70
|
)
|
|
14.49
|
|
||
Vested
|
(1,456
|
)
|
|
9.61
|
|
|
(693
|
)
|
|
15.81
|
|
||
Outstanding at December 31, 2016:
|
4,160
|
|
|
6.91
|
|
|
7,194
|
|
|
12.29
|
|
||
Granted
|
2,085
|
|
|
6.43
|
|
|
2,175
|
|
|
9.50
|
|
||
Forfeited
|
(137
|
)
|
|
6.91
|
|
|
(21
|
)
|
|
6.21
|
|
||
Vested
|
(1,925
|
)
|
|
7.51
|
|
|
(896
|
)
|
|
15.43
|
|
||
Outstanding at December 31, 2017:
|
4,183
|
|
|
6.39
|
|
|
8,452
|
|
|
11.26
|
|
||
Granted
|
2,402
|
|
|
7.07
|
|
|
8,111
|
|
|
12.38
|
|
||
Forfeited
|
(229
|
)
|
|
6.40
|
|
|
(302
|
)
|
|
8.95
|
|
||
Vested
|
(2,241
|
)
|
|
6.95
|
|
|
(9,545
|
)
|
|
13.75
|
|
||
Outstanding at December 31, 2018:
|
4,115
|
|
|
6.42
|
|
|
6,716
|
|
|
9.02
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
United States
|
$
|
41,026
|
|
|
$
|
6,068
|
|
|
$
|
5,083
|
|
Bermuda
|
(73,979
|
)
|
|
(66,914
|
)
|
|
(63,749
|
)
|
|||
Foreign—other
|
(17,907
|
)
|
|
(117,009
|
)
|
|
(235,898
|
)
|
|||
Loss before income taxes
|
$
|
(50,860
|
)
|
|
$
|
(177,855
|
)
|
|
$
|
(294,564
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Current:
|
|
|
|
|
|
|
|
|
|||
United States
|
$
|
122
|
|
|
$
|
10,976
|
|
|
$
|
12,675
|
|
Bermuda
|
—
|
|
|
—
|
|
|
—
|
|
|||
Foreign—other
|
33,864
|
|
|
24,456
|
|
|
102
|
|
|||
Total current
|
33,986
|
|
|
35,432
|
|
|
12,777
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
United States
|
8,514
|
|
|
15,310
|
|
|
(3,594
|
)
|
|||
Bermuda
|
—
|
|
|
—
|
|
|
—
|
|
|||
Foreign—other
|
631
|
|
|
(5,805
|
)
|
|
(19,967
|
)
|
|||
Total deferred
|
9,145
|
|
|
9,505
|
|
|
(23,561
|
)
|
|||
Income tax expense (benefit)
|
$
|
43,131
|
|
|
$
|
44,937
|
|
|
$
|
(10,784
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Tax at statutory rate(1)
|
$
|
(10,681
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Foreign income (loss) taxed at different rates
|
5,013
|
|
|
9,381
|
|
|
(57,898
|
)
|
|||
Net non-taxable expense / insurance recoveries
|
3,256
|
|
|
(30
|
)
|
|
8,694
|
|
|||
West Leo arbitration settlement
|
(2,834
|
)
|
|
1,736
|
|
|
1,098
|
|
|||
Non-deductible compensation
|
2,643
|
|
|
1,680
|
|
|
1,999
|
|
|||
Deferred tax liability - undistributed earnings
|
(2,565
|
)
|
|
2,565
|
|
|
—
|
|
|||
Non-deductible and other items
|
656
|
|
|
3,790
|
|
|
556
|
|
|||
Equity earnings - net of tax
|
(15,305
|
)
|
|
—
|
|
|
—
|
|
|||
Tax shortfall (windfall) on equity-based compensation, net
|
(387
|
)
|
|
3,086
|
|
|
5,504
|
|
|||
Change in valuation allowance
|
63,335
|
|
|
6,008
|
|
|
29,263
|
|
|||
Change in U.S. tax rate
|
—
|
|
|
16,721
|
|
|
—
|
|
|||
Total tax expense (benefit)
|
$
|
43,131
|
|
|
$
|
44,937
|
|
|
$
|
(10,784
|
)
|
Effective tax rate(2)
|
85
|
%
|
|
25
|
%
|
|
4
|
%
|
(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 2018 reconciliation of income tax expense is the U.S. statutory tax rate of
21%
. Our 2017 and 2016 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,
2018
,
2017
and
2016
were impacted by losses of
$261.2 million
,
$164.4 million
and
$121.4 million
, respectively, incurred in jurisdictions in which we are not subject to taxes and therefore do not generate any income tax benefits.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Deferred tax assets:
|
|
|
|
|
|
||
Foreign capitalized operating expenses
|
$
|
128,809
|
|
|
$
|
68,218
|
|
Foreign net operating losses
|
28,050
|
|
|
25,307
|
|
||
United States net operating losses
|
59,336
|
|
|
—
|
|
||
Equity compensation
|
11,408
|
|
|
20,783
|
|
||
Unrealized derivative losses
|
—
|
|
|
33,963
|
|
||
Asset retirement obligation and other
|
29,450
|
|
|
24,784
|
|
||
Total deferred tax assets
|
257,053
|
|
|
173,055
|
|
||
Valuation allowance
|
(156,860
|
)
|
|
(93,525
|
)
|
||
Total deferred tax assets, net
|
100,193
|
|
|
79,530
|
|
||
Deferred tax liabilities:
|
|
|
|
||||
Depletion, depreciation and amortization related to property and equipment
|
(547,389
|
)
|
|
(533,561
|
)
|
||
Unrealized derivative gains
|
(15,979
|
)
|
|
—
|
|
||
Total deferred tax liabilities
|
(563,368
|
)
|
|
(533,561
|
)
|
||
Net deferred tax liability
|
$
|
(463,175
|
)
|
|
$
|
(454,031
|
)
|
|
Years Ended
|
||||||||||
|
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands, except per share data)
|
||||||||||
Numerator:
|
|
|
|
|
|
|
|
|
|||
Net loss allocable to common stockholders(1)
|
$
|
(93,991
|
)
|
|
$
|
(222,792
|
)
|
|
$
|
(283,780
|
)
|
Denominator:
|
|
|
|
|
|
||||||
Weighted average number of shares outstanding:
|
|
|
|
|
|
||||||
Basic
|
404,585
|
|
|
388,375
|
|
|
385,402
|
|
|||
Restricted stock awards and units(1)(2)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Diluted
|
404,585
|
|
|
388,375
|
|
|
385,402
|
|
|||
Net loss per share:
|
|
|
|
|
|
||||||
Basic
|
$
|
(0.23
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.74
|
)
|
Diluted
|
$
|
(0.23
|
)
|
|
$
|
(0.57
|
)
|
|
$
|
(0.74
|
)
|
(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,
2018
,
2017
and
2016
, we excluded
10.6 million
,
12.9 million
and
11.8 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.
|
|
Payments Due By Year(1)
|
||||||||||||||||||||||||||
|
Total
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||
Operating leases(2)
|
$
|
36,508
|
|
|
$
|
2,775
|
|
|
$
|
4,173
|
|
|
$
|
3,276
|
|
|
$
|
3,326
|
|
|
$
|
3,376
|
|
|
$
|
19,582
|
|
(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.
|
(2)
|
Primarily relates to office leases.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
Accrued liabilities:
|
|
|
|
|
|
||
Exploration, development and production
|
$
|
92,613
|
|
|
$
|
144,717
|
|
Current asset retirement obligations
|
6,617
|
|
|
—
|
|
||
General and administrative expenses
|
39,373
|
|
|
31,124
|
|
||
Interest
|
18,152
|
|
|
20,457
|
|
||
Income taxes
|
8,958
|
|
|
17,423
|
|
||
Taxes other than income
|
4,613
|
|
|
3,270
|
|
||
Derivatives
|
441
|
|
|
—
|
|
||
Revenue payable
|
24,379
|
|
|
—
|
|
||
Other
|
450
|
|
|
2,421
|
|
||
|
$
|
195,596
|
|
|
$
|
219,412
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Loss on disposal of inventory
|
$
|
280
|
|
|
$
|
866
|
|
|
$
|
14,900
|
|
Gain on insurance settlements
|
—
|
|
|
(461
|
)
|
|
(4,003
|
)
|
|||
Disputed charges and related costs, net of recoveries
|
(9,753
|
)
|
|
4,962
|
|
|
11,299
|
|
|||
Other, net
|
2,972
|
|
|
(76
|
)
|
|
920
|
|
|||
Other expenses, net
|
$
|
(6,501
|
)
|
|
$
|
5,291
|
|
|
$
|
23,116
|
|
|
Ghana
|
|
Equatorial Guinea(1)
|
|
Mauritania/Senegal
|
|
United States(2)
|
|
Corporate & Other
|
|
Eliminations(3)
|
|
Total
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||
Year ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil and gas revenue
|
$
|
739,070
|
|
|
$
|
360,649
|
|
|
$
|
—
|
|
|
$
|
147,596
|
|
|
$
|
—
|
|
|
$
|
(360,649
|
)
|
|
$
|
886,666
|
|
Gain on sale of assets
|
—
|
|
|
7,666
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,666
|
|
|||||||
Other income, net
|
(17
|
)
|
|
(238
|
)
|
|
—
|
|
|
11
|
|
|
150,635
|
|
|
(142,354
|
)
|
|
8,037
|
|
|||||||
Total revenues and other income
|
739,053
|
|
|
368,077
|
|
|
—
|
|
|
147,607
|
|
|
150,635
|
|
|
(503,003
|
)
|
|
902,369
|
|
|||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil and gas production
|
189,104
|
|
|
73,843
|
|
|
—
|
|
|
30,470
|
|
|
5,153
|
|
|
(73,843
|
)
|
|
224,727
|
|
|||||||
Facilities insurance modifications, net
|
6,955
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,955
|
|
|||||||
Exploration expenses
|
58,276
|
|
|
38,164
|
|
|
7,262
|
|
|
66,962
|
|
|
131,180
|
|
|
(352
|
)
|
|
301,492
|
|
|||||||
General and administrative
|
19,342
|
|
|
5,351
|
|
|
5,220
|
|
|
10,534
|
|
|
168,542
|
|
|
(109,133
|
)
|
|
99,856
|
|
|||||||
Depletion and depreciation
|
265,805
|
|
|
134,983
|
|
|
61
|
|
|
59,835
|
|
|
4,134
|
|
|
(134,983
|
)
|
|
329,835
|
|
|||||||
Interest and other financing costs, net(4)
|
86,738
|
|
|
(12
|
)
|
|
(25,386
|
)
|
|
7,487
|
|
|
39,483
|
|
|
(7,134
|
)
|
|
101,176
|
|
|||||||
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
(57,615
|
)
|
|
26,185
|
|
|
—
|
|
|
(31,430
|
)
|
|||||||
(Gain) loss on equity method investments, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(72,881
|
)
|
|
(72,881
|
)
|
|||||||
Other expenses, net
|
16,414
|
|
|
(814
|
)
|
|
(23
|
)
|
|
598
|
|
|
3,510
|
|
|
(26,186
|
)
|
|
(6,501
|
)
|
|||||||
Total costs and expenses
|
642,634
|
|
|
251,515
|
|
|
(12,866
|
)
|
|
118,271
|
|
|
378,187
|
|
|
(424,512
|
)
|
|
953,229
|
|
|||||||
Loss before income taxes
|
96,419
|
|
|
116,562
|
|
|
12,866
|
|
|
29,336
|
|
|
(227,552
|
)
|
|
(78,491
|
)
|
|
(50,860
|
)
|
|||||||
Income tax expense (benefit)
|
34,494
|
|
|
78,491
|
|
|
—
|
|
|
6,163
|
|
|
2,474
|
|
|
(78,491
|
)
|
|
43,131
|
|
|||||||
Net loss
|
$
|
61,925
|
|
|
$
|
38,071
|
|
|
$
|
12,866
|
|
|
$
|
23,173
|
|
|
$
|
(230,026
|
)
|
|
$
|
—
|
|
|
$
|
(93,991
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Consolidated capital expenditures
|
$
|
105,942
|
|
|
$
|
32,156
|
|
|
$
|
11,962
|
|
|
$
|
95,993
|
|
|
$
|
139,381
|
|
|
$
|
—
|
|
|
$
|
385,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
As of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Property and equipment, net
|
$
|
1,698,194
|
|
|
$
|
3,919
|
|
|
$
|
411,448
|
|
|
$
|
1,308,670
|
|
|
$
|
37,470
|
|
|
$
|
—
|
|
|
$
|
3,459,701
|
|
Total assets
|
$
|
1,930,071
|
|
|
$
|
55,302
|
|
|
$
|
536,620
|
|
|
$
|
3,512,989
|
|
|
$
|
10,349,488
|
|
|
$
|
(12,296,281
|
)
|
|
$
|
4,088,189
|
|
(1)
|
Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion and depreciation 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.
|
|
Ghana
|
|
Equatorial Guinea(1)
|
|
Mauritania/Senegal
|
|
United States
|
|
Corporate & Other
|
|
Eliminations(2)
|
|
Total
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||
Year ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil and gas revenue
|
$
|
578,139
|
|
|
$
|
27,308
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(27,308
|
)
|
|
$
|
578,139
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Other income, net
|
5
|
|
|
147
|
|
|
—
|
|
|
—
|
|
|
$
|
219,968
|
|
|
(161,423
|
)
|
|
58,697
|
|
||||||
Total revenues and other income
|
578,144
|
|
|
27,455
|
|
|
—
|
|
|
—
|
|
|
219,968
|
|
|
(188,731
|
)
|
|
636,836
|
|
|||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil and gas production
|
137,584
|
|
|
7,755
|
|
|
—
|
|
|
—
|
|
|
(10,734
|
)
|
|
(7,755
|
)
|
|
126,850
|
|
|||||||
Facilities insurance modifications, net
|
(820
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(820
|
)
|
|||||||
Exploration expenses
|
394
|
|
|
86
|
|
|
71,456
|
|
|
—
|
|
|
144,114
|
|
|
—
|
|
|
216,050
|
|
|||||||
General and administrative
|
14,836
|
|
|
672
|
|
|
8,298
|
|
|
—
|
|
|
138,661
|
|
|
(94,165
|
)
|
|
68,302
|
|
|||||||
Depletion and depreciation
|
251,890
|
|
|
11,181
|
|
|
20
|
|
|
—
|
|
|
3,293
|
|
|
(11,181
|
)
|
|
255,203
|
|
|||||||
Interest and other financing costs, net(3)
|
71,592
|
|
|
—
|
|
|
(16,065
|
)
|
|
—
|
|
|
29,202
|
|
|
(7,134
|
)
|
|
77,595
|
|
|||||||
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59,968
|
|
|
—
|
|
|
59,968
|
|
|||||||
Loss on equity method investments, net
|
—
|
|
|
—
|
|
|
11,486
|
|
|
—
|
|
|
—
|
|
|
(5,234
|
)
|
|
6,252
|
|
|||||||
Other expenses, net
|
64,768
|
|
|
—
|
|
|
867
|
|
|
—
|
|
|
(376
|
)
|
|
(59,968
|
)
|
|
5,291
|
|
|||||||
Total costs and expenses
|
540,244
|
|
|
19,694
|
|
|
76,062
|
|
|
—
|
|
|
364,128
|
|
|
(185,437
|
)
|
|
814,691
|
|
|||||||
Income (loss) before income taxes
|
37,900
|
|
|
7,761
|
|
|
(76,062
|
)
|
|
—
|
|
|
(144,160
|
)
|
|
(3,294
|
)
|
|
(177,855
|
)
|
|||||||
Income tax expense (benefit)
|
18,649
|
|
|
3,294
|
|
|
3
|
|
|
—
|
|
|
26,285
|
|
|
(3,294
|
)
|
|
44,937
|
|
|||||||
Net income (loss)
|
$
|
19,251
|
|
|
$
|
4,467
|
|
|
$
|
(76,065
|
)
|
|
$
|
—
|
|
|
$
|
(170,445
|
)
|
|
$
|
—
|
|
|
$
|
(222,792
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Consolidated capital expenditures
|
$
|
5,545
|
|
|
$
|
1,995
|
|
|
$
|
(80,929
|
)
|
|
$
|
—
|
|
|
$
|
130,821
|
|
|
$
|
—
|
|
|
$
|
57,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
As of December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Property and equipment, net
|
$
|
1,901,127
|
|
|
$
|
1,908
|
|
|
$
|
381,422
|
|
|
$
|
—
|
|
|
$
|
33,371
|
|
|
$
|
—
|
|
|
$
|
2,317,828
|
|
Total assets
|
$
|
2,263,824
|
|
|
$
|
237,835
|
|
|
$
|
570,044
|
|
|
$
|
—
|
|
|
$
|
8,671,437
|
|
|
$
|
(8,550,537
|
)
|
|
$
|
3,192,603
|
|
(1)
|
Includes our proportionate share of our equity method investment in KTIPI, including our basis difference which is reflected in depletion and depreciation 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.
|
|
Ghana
|
|
Equatorial Guinea
|
|
Mauritania/Senegal
|
|
United States
|
|
Corporate & Other
|
|
Eliminations
|
|
Total
|
||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||||||
Year ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil and gas revenue
|
$
|
310,377
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
310,377
|
|
Gain on sale of assets
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Other income, net
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
227,101
|
|
|
(152,130
|
)
|
|
74,978
|
|
||||||
Total revenues and other income
|
310,384
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
227,101
|
|
|
(152,130
|
)
|
|
385,355
|
|
|||||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Oil and gas production
|
121,329
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,962
|
)
|
|
—
|
|
|
119,367
|
|
|||||||
Facilities insurance modifications, net
|
14,961
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,961
|
|
|||||||
Exploration expenses
|
1,211
|
|
|
9
|
|
|
63,186
|
|
|
—
|
|
|
137,874
|
|
|
—
|
|
|
202,280
|
|
|||||||
General and administrative
|
9,490
|
|
|
—
|
|
|
21,530
|
|
|
—
|
|
|
153,577
|
|
|
(96,974
|
)
|
|
87,623
|
|
|||||||
Depletion and depreciation
|
137,094
|
|
|
—
|
|
|
97
|
|
|
—
|
|
|
3,213
|
|
|
—
|
|
|
140,404
|
|
|||||||
Interest and other financing costs, net(1)
|
45,403
|
|
|
—
|
|
|
(22,404
|
)
|
|
—
|
|
|
28,282
|
|
|
(7,134
|
)
|
|
44,147
|
|
|||||||
Derivatives, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48,021
|
|
|
—
|
|
|
48,021
|
|
|||||||
Loss on equity method investments, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Other expenses, net
|
67,793
|
|
|
—
|
|
|
454
|
|
|
—
|
|
|
2,890
|
|
|
(48,021
|
)
|
|
23,116
|
|
|||||||
Total costs and expenses
|
397,281
|
|
|
9
|
|
|
62,863
|
|
|
—
|
|
|
371,895
|
|
|
(152,129
|
)
|
|
679,919
|
|
|||||||
Income (loss) before income taxes
|
(86,897
|
)
|
|
(9
|
)
|
|
(62,863
|
)
|
|
—
|
|
|
(144,794
|
)
|
|
(1
|
)
|
|
(294,564
|
)
|
|||||||
Income tax expense (benefit)
|
(19,866
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,082
|
|
|
—
|
|
|
(10,784
|
)
|
|||||||
Net income (loss)
|
$
|
(67,031
|
)
|
|
$
|
(9
|
)
|
|
$
|
(62,863
|
)
|
|
$
|
—
|
|
|
$
|
(153,876
|
)
|
|
$
|
(1
|
)
|
|
$
|
(283,780
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Consolidated capital expenditures
|
$
|
221,294
|
|
|
$
|
9
|
|
|
$
|
283,442
|
|
|
$
|
—
|
|
|
$
|
139,765
|
|
|
$
|
—
|
|
|
$
|
644,510
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
As of December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Property and equipment, net
|
$
|
2,129,873
|
|
|
$
|
—
|
|
|
$
|
529,071
|
|
|
$
|
—
|
|
|
$
|
49,948
|
|
|
$
|
—
|
|
|
$
|
2,708,892
|
|
Total assets
|
$
|
2,484,497
|
|
|
$
|
(3
|
)
|
|
$
|
551,250
|
|
|
$
|
—
|
|
|
$
|
8,205,043
|
|
|
$
|
(7,899,322
|
)
|
|
$
|
3,341,465
|
|
(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.
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(In thousands)
|
||||||||||
Consolidated capital expenditures:
|
|
|
|
|
|
||||||
Consolidated Statements of Cash Flows - Investing activities:
|
|
|
|
|
|
||||||
Oil and gas assets
|
$
|
213,806
|
|
|
$
|
140,495
|
|
|
$
|
535,975
|
|
Other property
|
7,935
|
|
|
2,858
|
|
|
1,998
|
|
|||
Adjustments:
|
|
|
|
|
|
||||||
Changes in capital accruals
|
26,669
|
|
|
(6,337
|
)
|
|
(26,725
|
)
|
|||
Exploration expense, excluding unsuccessful well costs(1)
|
178,293
|
|
|
172,849
|
|
|
199,806
|
|
|||
Capitalized interest
|
(28,331
|
)
|
|
(30,282
|
)
|
|
(59,803
|
)
|
|||
Proceeds on sale of assets
|
(13,703
|
)
|
|
(222,068
|
)
|
|
(210
|
)
|
|||
Other
|
765
|
|
|
(83
|
)
|
|
(6,531
|
)
|
|||
Total consolidated capital expenditures
|
$
|
385,434
|
|
|
$
|
57,432
|
|
|
$
|
644,510
|
|
(1)
|
Unsuccessful well costs are included in oil and gas assets when incurred.
|
|
Kosmos Entities
|
|
Equity Method Investment - Equatorial Guinea
|
|
|
|||||||||||||||
|
Oil
|
|
Gas
|
|
Total
|
|
Oil
|
|
Gas
|
|
Total
|
|
Total
|
|||||||
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBoe)
|
|
(MMBbl)
|
|
(Bcf)
|
|
(MMBoe)
|
|
(MMBoe)
|
|||||||
Net proved developed and undeveloped reserves at December 31, 2015(1)
|
74
|
|
|
14
|
|
|
76
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
76
|
|
Production
|
(7
|
)
|
|
(1
|
)
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
Revision in estimate(2)
|
7
|
|
|
2
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Net proved developed and undeveloped reserves at December 31, 2016(1)
|
74
|
|
|
15
|
|
|
77
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
77
|
|
Extensions and discoveries
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Production
|
(11
|
)
|
|
(1
|
)
|
|
(11
|
)
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
(12
|
)
|
Revision in estimate(3)
|
18
|
|
|
35
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24
|
|
Purchases of minerals-in-place(4)
|
—
|
|
|
—
|
|
|
—
|
|
|
20
|
|
|
13
|
|
|
21
|
|
|
21
|
|
Net proved developed and undeveloped reserves at December 31, 2017(1)
|
82
|
|
|
49
|
|
|
89
|
|
|
19
|
|
|
13
|
|
|
21
|
|
|
110
|
|
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(13
|
)
|
|
(3
|
)
|
|
(14
|
)
|
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
|
(19
|
)
|
Revision in estimate(5)
|
11
|
|
|
(1
|
)
|
|
11
|
|
|
10
|
|
|
1
|
|
|
10
|
|
|
21
|
|
Purchases of minerals-in-place(6)
|
47
|
|
|
40
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54
|
|
Net proved developed and undeveloped reserves at December 31, 2018(1)
|
127
|
|
|
85
|
|
|
141
|
|
|
24
|
|
|
14
|
|
|
26
|
|
|
167
|
|
Proved developed reserves(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
64
|
|
|
13
|
|
|
66
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
66
|
|
December 31, 2017
|
59
|
|
|
38
|
|
|
65
|
|
|
18
|
|
|
13
|
|
|
20
|
|
|
85
|
|
December 31, 2018
|
81
|
|
|
57
|
|
|
91
|
|
|
23
|
|
|
14
|
|
|
25
|
|
|
116
|
|
Proved undeveloped reserves(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
10
|
|
|
2
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
December 31, 2017
|
23
|
|
|
11
|
|
|
24
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
25
|
|
December 31, 2018
|
45
|
|
|
28
|
|
|
50
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
51
|
|
(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 an 8 MMBbl increase associated with positive revisions to the TEN fields as a result of the completion of seven wells along with the initiation of TEN production partially offset by 1 MMBbl of negative revisions to the Jubilee Field due to decreased pricing.
|
(3)
|
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.
|
(4)
|
The increase in purchase of minerals in place is related to Equatorial Guinea, representing the reserves associated with our equity method investment.
|
(5)
|
The increase in proved reserves is a result of a 10 MMBoe increase in Jubilee related to strong field performance, positive drilling results and increased estimate of original oil in place. Changes at TEN include a positive revision of 4 MMBbl due to increased estimate of original oil in place, new drilling and development plan updates, and a negative revision of 3 MMBbl due to recovery factor adjustment from dynamic modeling. Changes at Equatorial Guinea are primarily a 4 MMBbl positive revision due to strong field performance at both Ceiba and Okume Complex and a 6 MMBbl positive revision due to reservoir management strategies (re-opening shut-in wells, stimulations, surface/subsurface equipment installation).
|
(6)
|
The increase in purchase of minerals in place is related to the DGE acquisition completed in September 2018.
|
|
Ghana
|
|
U.S. Gulf of Mexico
|
|
Other(1)
|
|
Kosmos Total
|
|
Equity Method Investment-Equatorial Guinea(2)
|
|
Total
|
||||||||||||
|
(In thousands)
|
||||||||||||||||||||||
As of December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Unproved properties
|
$
|
—
|
|
|
$
|
318,831
|
|
|
$
|
440,641
|
|
|
$
|
759,472
|
|
|
$
|
—
|
|
|
$
|
759,472
|
|
Proved properties
|
3,191,157
|
|
|
1,045,332
|
|
|
—
|
|
|
4,236,489
|
|
|
2,850,316
|
|
|
7,086,805
|
|
||||||
|
3,191,157
|
|
|
1,364,163
|
|
|
440,641
|
|
|
4,995,961
|
|
|
2,850,316
|
|
|
7,846,277
|
|
||||||
Accumulated depletion
|
(1,493,111
|
)
|
|
(57,986
|
)
|
|
—
|
|
|
(1,551,097
|
)
|
|
(2,717,020
|
)
|
|
(4,268,117
|
)
|
||||||
Net capitalized costs
|
$
|
1,698,046
|
|
|
$
|
1,306,177
|
|
|
$
|
440,641
|
|
|
$
|
3,444,864
|
|
|
$
|
133,296
|
|
|
$
|
3,578,160
|
|
As of December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Unproved properties
|
$
|
55,179
|
|
|
$
|
—
|
|
|
$
|
409,930
|
|
|
$
|
465,109
|
|
|
$
|
—
|
|
|
$
|
465,109
|
|
Proved properties
|
3,080,670
|
|
|
—
|
|
|
—
|
|
|
3,080,670
|
|
|
2,850,521
|
|
|
5,931,191
|
|
||||||
|
3,135,849
|
|
|
—
|
|
|
409,930
|
|
|
3,545,779
|
|
|
2,850,521
|
|
|
6,396,300
|
|
||||||
Accumulated depletion
|
(1,234,806
|
)
|
|
—
|
|
|
—
|
|
|
(1,234,806
|
)
|
|
(2,678,897
|
)
|
|
(3,913,703
|
)
|
||||||
Net capitalized costs
|
$
|
1,901,043
|
|
|
$
|
—
|
|
|
$
|
409,930
|
|
|
$
|
2,310,973
|
|
|
$
|
171,624
|
|
|
$
|
2,482,597
|
|
|
Ghana
|
|
U.S. Gulf of Mexico
|
|
Other(1)
|
|
Kosmos Total
|
|
Equity Method Investment-Equatorial Guinea(2)
|
|
Total
|
||||||||||||
|
(In thousands)
|
||||||||||||||||||||||
Year ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Unproved
|
$
|
—
|
|
|
$
|
302,688
|
|
|
$
|
2,975
|
|
|
$
|
305,663
|
|
|
$
|
—
|
|
|
$
|
305,663
|
|
Proved
|
—
|
|
|
1,037,511
|
|
|
—
|
|
|
1,037,511
|
|
|
—
|
|
|
1,037,511
|
|
||||||
Exploration
|
3,182
|
|
|
69,673
|
|
|
199,423
|
|
|
272,278
|
|
|
—
|
|
|
272,278
|
|
||||||
Development
|
110,401
|
|
|
21,252
|
|
|
4,569
|
|
|
136,222
|
|
|
—
|
|
|
136,222
|
|
||||||
Total costs incurred
|
$
|
113,583
|
|
|
$
|
1,431,124
|
|
|
$
|
206,967
|
|
|
$
|
1,751,674
|
|
|
$
|
—
|
|
|
$
|
1,751,674
|
|
Year ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Unproved
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,865
|
|
|
$
|
9,865
|
|
|
$
|
—
|
|
|
$
|
9,865
|
|
Proved(3)
|
—
|
|
|
—
|
|
|
231,280
|
|
|
231,280
|
|
|
—
|
|
|
231,280
|
|
||||||
Exploration
|
15,150
|
|
|
—
|
|
|
55,632
|
|
|
70,782
|
|
|
—
|
|
|
70,782
|
|
||||||
Development
|
1,364
|
|
|
—
|
|
|
—
|
|
|
1,364
|
|
|
—
|
|
|
1,364
|
|
||||||
Total costs incurred
|
$
|
16,514
|
|
|
$
|
—
|
|
|
$
|
296,777
|
|
|
$
|
313,291
|
|
|
$
|
—
|
|
|
$
|
313,291
|
|
Year ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Unproved
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
17,322
|
|
|
$
|
17,322
|
|
|
|
|
|
||||
Proved
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
||||||||
Exploration
|
11,871
|
|
|
—
|
|
|
425,229
|
|
|
437,100
|
|
|
|
|
|
||||||||
Development
|
265,451
|
|
|
—
|
|
|
—
|
|
|
265,451
|
|
|
|
|
|
||||||||
Total costs incurred
|
$
|
277,322
|
|
|
$
|
—
|
|
|
$
|
442,551
|
|
|
$
|
719,873
|
|
|
|
|
|
(1)
|
Includes Africa (excluding Ghana), 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.
|
|
Ghana
|
|
U.S. Gulf of Mexico
|
|
Equity Method Investment-Equatorial Guinea
|
|
Total
|
||||||||
|
(In millions)
|
||||||||||||||
At December 31, 2018
|
|
|
|
|
|
|
|
|
|||||||
Future cash inflows
|
$
|
5,882
|
|
|
$
|
2,951
|
|
|
$
|
1,735
|
|
|
$
|
10,568
|
|
Future production costs
|
(1,613
|
)
|
|
(338
|
)
|
|
(583
|
)
|
|
(2,534
|
)
|
||||
Future development costs
|
(928
|
)
|
|
(467
|
)
|
|
(378
|
)
|
|
(1,773
|
)
|
||||
Future tax expenses
|
(1,052
|
)
|
|
(379
|
)
|
|
(416
|
)
|
|
(1,847
|
)
|
||||
Future net cash flows
|
2,289
|
|
|
1,767
|
|
|
358
|
|
|
4,414
|
|
||||
10% annual discount for estimated timing of cash flows
|
(749
|
)
|
|
(397
|
)
|
|
33
|
|
|
(1,113
|
)
|
||||
Standardized measure of discounted future net cash flows
|
$
|
1,540
|
|
|
$
|
1,370
|
|
|
$
|
391
|
|
|
$
|
3,301
|
|
At December 31, 2017
|
|
|
|
|
|
|
|
|
|
||||||
Future cash inflows
|
$
|
4,473
|
|
|
|
|
$
|
1,003
|
|
|
$
|
5,476
|
|
||
Future production costs
|
(1,925
|
)
|
|
|
|
(473
|
)
|
|
(2,398
|
)
|
|||||
Future development costs
|
(1,059
|
)
|
|
|
|
(296
|
)
|
|
(1,355
|
)
|
|||||
Future Ghanaian tax expenses(1)
|
(203
|
)
|
|
|
|
(225
|
)
|
|
(428
|
)
|
|||||
Future net cash flows
|
1,286
|
|
|
|
|
|
9
|
|
|
1,295
|
|
||||
10% annual discount for estimated timing of cash flows
|
(315
|
)
|
|
|
|
121
|
|
|
(194
|
)
|
|||||
Standardized measure of discounted future net cash flows
|
$
|
971
|
|
|
|
|
|
$
|
130
|
|
|
$
|
1,101
|
|
|
At December 31, 2016
|
|
|
|
|
|
|
|
|
|||||||
Future cash inflows
|
$
|
3,204
|
|
|
|
|
|
|
|
||||||
Future production costs
|
(1,437
|
)
|
|
|
|
|
|
|
|||||||
Future development costs
|
(428
|
)
|
|
|
|
|
|
|
|||||||
Future Ghanaian tax expenses(1)
|
(228
|
)
|
|
|
|
|
|
|
|||||||
Future net cash flows
|
1,111
|
|
|
|
|
|
|
|
|
||||||
10% annual discount for estimated timing of cash flows
|
(265
|
)
|
|
|
|
|
|
|
|||||||
Standardized measure of discounted future net cash flows
|
$
|
846
|
|
|
|
|
|
|
|
|
(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,
2017
and
2016
, respectively, only reflect the effects of future tax expense levied at an asset level.
|
|
Ghana
|
|
U.S. Gulf of Mexico
|
|
Equity Method Investment-Equatorial Guinea
|
|
Total
|
||||||||
|
(In millions)
|
||||||||||||||
Balance at December 31, 2015
|
$
|
1,169
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,169
|
|
Sales and transfers 2016
|
(191
|
)
|
|
—
|
|
|
—
|
|
|
(191
|
)
|
||||
Net changes in prices and costs
|
(653
|
)
|
|
—
|
|
|
—
|
|
|
(653
|
)
|
||||
Previously estimated development costs incurred during the period
|
225
|
|
|
—
|
|
|
—
|
|
|
225
|
|
||||
Net changes in development costs
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Revisions of previous quantity estimates
|
65
|
|
|
—
|
|
|
—
|
|
|
65
|
|
||||
Net changes in Ghanaian tax expenses(1)
|
143
|
|
|
—
|
|
|
—
|
|
|
143
|
|
||||
Accretion of discount
|
145
|
|
|
—
|
|
|
—
|
|
|
145
|
|
||||
Changes in timing and other
|
(61
|
)
|
|
—
|
|
|
—
|
|
|
(61
|
)
|
||||
Balance at December 31, 2016
|
$
|
846
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
846
|
|
Purchase of minerals in place
|
—
|
|
|
—
|
|
|
146
|
|
|
146
|
|
||||
Sales and transfers 2017
|
(451
|
)
|
|
—
|
|
|
(16
|
)
|
|
(467
|
)
|
||||
Extensions and discoveries
|
21
|
|
|
—
|
|
|
—
|
|
|
21
|
|
||||
Net changes in prices and costs
|
485
|
|
|
—
|
|
|
—
|
|
|
485
|
|
||||
Previously estimated development costs incurred during the period
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
||||
Net changes in development costs
|
(388
|
)
|
|
—
|
|
|
—
|
|
|
(388
|
)
|
||||
Revisions of previous quantity estimates
|
415
|
|
|
—
|
|
|
—
|
|
|
415
|
|
||||
Net changes in tax expenses(1)
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
||||
Accretion of discount
|
98
|
|
|
—
|
|
|
—
|
|
|
|
|||||
Changes in timing and other
|
(53
|
)
|
|
—
|
|
|
—
|
|
|
|
|||||
Balance at December 31, 2017
|
$
|
971
|
|
|
$
|
—
|
|
|
$
|
130
|
|
|
$
|
1,101
|
|
Purchase of minerals in place
|
—
|
|
|
1,487
|
|
|
—
|
|
|
1,487
|
|
||||
Sales and transfers 2018
|
(545
|
)
|
|
(117
|
)
|
|
(287
|
)
|
|
(949
|
)
|
||||
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Net changes in prices and costs
|
1,154
|
|
|
—
|
|
|
408
|
|
|
1,562
|
|
||||
Previously estimated development costs incurred during the period
|
105
|
|
|
—
|
|
|
—
|
|
|
105
|
|
||||
Net changes in development costs
|
181
|
|
|
—
|
|
|
29
|
|
|
210
|
|
||||
Revisions of previous quantity estimates
|
485
|
|
|
—
|
|
|
574
|
|
|
1,059
|
|
||||
Net changes in tax expenses
|
(565
|
)
|
|
—
|
|
|
(136
|
)
|
|
(701
|
)
|
||||
Accretion of discount
|
112
|
|
|
—
|
|
|
30
|
|
|
142
|
|
||||
Changes in timing and other
|
(358
|
)
|
|
—
|
|
|
(357
|
)
|
|
(715
|
)
|
||||
Balance at December 31, 2018
|
$
|
1,540
|
|
|
$
|
1,370
|
|
|
$
|
391
|
|
|
$
|
3,301
|
|
(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,
2017
and
2016
, respectively, only reflect the effects of future tax expense levied at an asset level.
|
|
Quarter Ended
|
||||||||||||||
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
||||||||
|
(In thousands, except per share data)
|
||||||||||||||
2018
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenues and other income
|
$
|
127,177
|
|
|
$
|
215,473
|
|
|
$
|
250,219
|
|
|
$
|
309,500
|
|
Costs and expenses
|
201,751
|
|
|
364,091
|
|
|
364,912
|
|
|
22,475
|
|
||||
Net income (loss)
|
(50,226
|
)
|
|
(103,273
|
)
|
|
(126,057
|
)
|
|
185,565
|
|
||||
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic(1)
|
(0.13
|
)
|
|
(0.26
|
)
|
|
(0.31
|
)
|
|
0.44
|
|
||||
Diluted(1)
|
(0.13
|
)
|
|
(0.26
|
)
|
|
(0.31
|
)
|
|
0.43
|
|
||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenues and other income
|
$
|
151,966
|
|
|
$
|
146,524
|
|
|
$
|
151,242
|
|
|
$
|
187,104
|
|
Costs and expenses
|
158,630
|
|
|
131,252
|
|
|
216,162
|
|
|
308,647
|
|
||||
Net loss
|
(28,841
|
)
|
|
(8,467
|
)
|
|
(63,405
|
)
|
|
(122,079
|
)
|
||||
Net loss per share:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic(1)
|
(0.07
|
)
|
|
(0.02
|
)
|
|
(0.16
|
)
|
|
(0.31
|
)
|
||||
Diluted(1)
|
(0.07
|
)
|
|
(0.02
|
)
|
|
(0.16
|
)
|
|
(0.31
|
)
|
(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.
|
(a)
|
The following documents are filed as part of this report:
|
(1)
|
Financial statements
|
(2)
|
Financial statement schedules
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Assets
|
|
|
|
|
|
||
Current assets:
|
|
|
|
|
|
||
Cash and cash equivalents
|
$
|
6,776
|
|
|
$
|
297
|
|
Receivables from subsidiaries
|
2,890
|
|
|
—
|
|
||
Note receivable from subsidiary
|
7,941
|
|
|
—
|
|
||
Prepaid expenses and other
|
313
|
|
|
290
|
|
||
Total current assets
|
17,920
|
|
|
587
|
|
||
Investment in subsidiaries at equity
|
1,432,468
|
|
|
1,419,890
|
|
||
Long-term note receivable from subsidiary
|
607,943
|
|
|
—
|
|
||
Deferred financing costs, net of accumulated amortization of $12,065 and $13,951 at December 31, 2018 and December 31, 2017, respectively
|
8,937
|
|
|
2,510
|
|
||
Restricted cash
|
305
|
|
|
—
|
|
||
Long-term deferred tax asset
|
(1,132
|
)
|
|
—
|
|
||
Total assets
|
$
|
2,066,441
|
|
|
$
|
1,422,987
|
|
Liabilities and shareholders’ equity
|
|
|
|
|
|
||
Current liabilities:
|
|
|
|
|
|
||
Accounts payable
|
$
|
975
|
|
|
$
|
4
|
|
Accounts payable to subsidiaries
|
—
|
|
|
332
|
|
||
Accrued liabilities
|
18,972
|
|
|
19,128
|
|
||
Total current liabilities
|
19,947
|
|
|
19,464
|
|
||
Long-term debt
|
836,016
|
|
|
506,411
|
|
||
Long-term note payable to subsidiary
|
269,000
|
|
|
—
|
|
||
Shareholders’ equity:
|
|
|
|
|
|
||
Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at December 31, 2018 and December 31, 2017
|
—
|
|
|
—
|
|
||
Common stock, $0.01 par value; 2,000,000,000 authorized shares; 442,914,675 and 398,599,457 issued at December 31, 2018 and December 31, 2017, respectively
|
4,429
|
|
|
3,986
|
|
||
Additional paid-in capital
|
2,341,249
|
|
|
2,014,525
|
|
||
Accumulated deficit
|
(1,167,193
|
)
|
|
(1,073,202
|
)
|
||
Treasury stock, at cost, 44,263,269 and 9,188,819 shares at December 31, 2018 and December 31, 2017, respectively
|
(237,007
|
)
|
|
(48,197
|
)
|
||
Total shareholders’ equity
|
941,478
|
|
|
897,112
|
|
||
Total liabilities and shareholders’ equity
|
$
|
2,066,441
|
|
|
$
|
1,422,987
|
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|||
Oil and gas revenue
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total revenues and other income
|
—
|
|
|
—
|
|
|
—
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|||
General and administrative
|
47,279
|
|
|
51,544
|
|
|
48,542
|
|
|||
General and administrative recoveries—related party
|
(36,197
|
)
|
|
(40,266
|
)
|
|
(40,047
|
)
|
|||
Interest and other financing costs, net
|
66,055
|
|
|
55,596
|
|
|
55,253
|
|
|||
Interest and other financing costs, net—related party
|
(7,941
|
)
|
|
—
|
|
|
—
|
|
|||
Other expenses, net
|
49
|
|
|
40
|
|
|
1
|
|
|||
Equity in losses of subsidiaries
|
23,614
|
|
|
155,878
|
|
|
220,031
|
|
|||
Total costs and expenses
|
92,859
|
|
|
222,792
|
|
|
283,780
|
|
|||
Loss before income taxes
|
(92,859
|
)
|
|
(222,792
|
)
|
|
(283,780
|
)
|
|||
Income tax expense
|
1,132
|
|
|
—
|
|
|
—
|
|
|||
Net loss
|
$
|
(93,991
|
)
|
|
$
|
(222,792
|
)
|
|
$
|
(283,780
|
)
|
|
Years Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Operating activities
|
|
|
|
|
|
|
|
|
|||
Net loss
|
$
|
(93,991
|
)
|
|
$
|
(222,792
|
)
|
|
$
|
(283,780
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|||
Equity in losses of subsidiaries
|
23,614
|
|
|
155,878
|
|
|
220,031
|
|
|||
Equity-based compensation
|
35,230
|
|
|
39,913
|
|
|
40,423
|
|
|||
Amortization
|
7,292
|
|
|
3,070
|
|
|
3,070
|
|
|||
Deferred income taxes
|
1,132
|
|
|
—
|
|
|
—
|
|
|||
Other
|
268
|
|
|
3,884
|
|
|
3,530
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
Decrease in receivables
|
1,234
|
|
|
986
|
|
|
—
|
|
|||
(Increase) decrease in prepaid expenses and other
|
(23
|
)
|
|
127
|
|
|
52
|
|
|||
(Increase) decrease due to/from related party
|
(42,163
|
)
|
|
14,463
|
|
|
(15,201
|
)
|
|||
Increase in accounts payable and accrued liabilities
|
816
|
|
|
1,179
|
|
|
312
|
|
|||
Net cash provided by (used in) operating activities
|
(66,591
|
)
|
|
(3,292
|
)
|
|
(31,563
|
)
|
|||
Investing activities
|
|
|
|
|
|
|
|
||||
Investment in subsidiaries
|
(36,192
|
)
|
|
4,691
|
|
|
(40,047
|
)
|
|||
Net cash provided by (used in) investing activities
|
(36,192
|
)
|
|
4,691
|
|
|
(40,047
|
)
|
|||
Financing activities
|
|
|
|
|
|
|
|
||||
Borrowings under long-term debt
|
400,000
|
|
|
—
|
|
|
—
|
|
|||
Payments on long-term debt
|
(75,000
|
)
|
|
|
|
|
|||||
Purchase of treasury stock
|
(206,051
|
)
|
|
(2,194
|
)
|
|
(1,981
|
)
|
|||
Deferred financing costs
|
(9,382
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
109,567
|
|
|
(2,194
|
)
|
|
(1,981
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
6,784
|
|
|
(795
|
)
|
|
(73,591
|
)
|
|||
Cash, cash equivalents and restricted cash at beginning of period
|
297
|
|
|
1,092
|
|
|
74,683
|
|
|||
Cash, cash equivalents and restricted cash at end of period
|
$
|
7,081
|
|
|
$
|
297
|
|
|
$
|
1,092
|
|
|
|
|
|
|
|
||||||
Non-cash activity:
|
|
|
|
|
|
||||||
Issuance of common stock for related party receivable
|
$
|
307,944
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
Additions
|
|
|
|
|
||||||||||||
Description
|
|
Balance January 1,
|
|
Charged to Costs and Expenses
|
|
Charged To Other Accounts
|
|
Deductions From Reserves
|
|
Balance December 31,
|
||||||||||
2018
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful receivables
|
|
$
|
—
|
|
|
$
|
1,211
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,211
|
|
Allowance for deferred tax assets
|
|
$
|
93,525
|
|
|
$
|
63,335
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
156,860
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful receivables
|
|
$
|
574
|
|
|
$
|
77
|
|
|
$
|
—
|
|
|
$
|
(651
|
)
|
|
$
|
—
|
|
Allowance for deferred tax assets
|
|
$
|
87,517
|
|
|
$
|
6,008
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
93,525
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Allowance for doubtful receivables
|
|
$
|
—
|
|
|
$
|
574
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
574
|
|
Allowance for deferred tax assets
|
|
$
|
116,541
|
|
|
$
|
(29,024
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
87,517
|
|
|
KOSMOS ENERGY LTD.
|
|
|
|
|
Date: February 28, 2019
|
By:
|
/s/ Thomas P. Chambers
|
|
|
Thomas P. Chambers
Senior Vice President and Chief Financial Officer
|
Signature
|
Title
|
Date
|
|
|
|
/s/ Andrew G. Inglis
|
Chairman of the Board of Directors and Chief Executive Officer (Principal Executive Officer)
|
February 28, 2019
|
Andrew G. Inglis
|
||
|
|
|
/s/ Thomas P. Chambers
|
Senior Vice President and Chief Financial Officer (Principal Financial Officer)
|
February 28, 2019
|
Thomas P. Chambers
|
||
|
|
|
/s/ Paul M. Nobel
|
Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)
|
February 28, 2019
|
Paul M. Nobel
|
||
|
|
|
/s/ Brian F. Maxted
|
Director
|
February 28, 2019
|
Brian F. Maxted
|
||
|
|
|
/s/ Sir Richard B. Dearlove
|
Director
|
February 28, 2019
|
Sir Richard B. Dearlove
|
||
|
|
|
/s/ Deanna L. Goodwin
|
Director
|
February 28, 2019
|
Deanna L. Goodwin
|
||
|
|
|
/s/ Adebayo O. Ogunlesi
|
Director
|
February 28, 2019
|
Adebayo O. Ogunlesi
|
||
|
|
|
/s/ Chris Tong
|
Director
|
February 28, 2019
|
Chris Tong
|
Exhibit
Number
|
|
Description of Document
|
|
|
|
|
Governing Documents
|
3.1
|
|
|
|
3.2
|
|
|
|
4.1
|
|
|
|
|
|
|
Operating Agreements
|
|
|
Certain of the agreements listed below have been filed pursuant to the Company’s voluntary compliance with international transparency standards and are not material contracts as such term is used in Item 601(b)(10) of Regulation S-K.
|
|
|
|
|
Ghana
|
10.1
|
|
|
|
10.2
|
|
|
|
10.3
|
|
|
|
10.4
|
|
|
|
10.5
|
|
|
|
10.6
|
|
|
|
|
|
|
Sao Tome and Principe
|
10.7
|
|
|
|
10.8
|
|
|
|
10.9
|
|
|
|
10.10
|
|
|
|
10.11
|
|
|
Exhibit
Number
|
|
Description of Document
|
|
10.12
|
|
|
|
10.13
|
|
|
|
10.14
|
|
|
|
10.15
|
|
|
|
10.16
|
|
|
|
10.17
|
|
|
|
|
|
|
Senegal
|
10.18
|
|
|
|
10.19
|
|
|
|
10.20
|
|
|
|
|
|
|
Suriname
|
10.21
|
|
|
|
10.22
|
|
|
|
|
|
|
Mauritania
|
10.23
|
|
|
|
10.24
|
|
|
|
10.25
|
|
|
|
10.26
|
|
|
Exhibit
Number
|
|
Description of Document
|
|
10.27
|
|
|
|
|
|
|
Equatorial Guinea
|
10.28
|
|
|
|
10.29
|
|
|
|
10.30
|
|
|
|
10.31
|
|
|
|
10.32
|
|
|
|
10.33
|
|
|
|
10.34
|
|
|
|
10.35
|
|
|
|
10.36
|
|
|
|
|
|
|
Cote d'Ivoire
|
10.37
|
|
|
|
10.38
|
|
|
|
10.39
|
|
|
Exhibit
Number
|
|
Description of Document
|
|
10.40
|
|
|
|
10.41
|
|
|
|
|
|
Namibia
|
|
10.42*
|
|
|
|
10.43*
|
|
|
|
10.44*
|
|
|
|
|
|
|
Financing Agreements
|
10.45
|
|
|
|
10.46
|
|
|
|
10.47
|
|
|
|
10.48
|
|
|
|
|
|
|
Agreements with Shareholders and Directors
|
10.49
|
|
|
|
10.50
|
|
|
|
10.51
|
|
|
|
10.52
|
|
|
|
10.53
|
|
|
|
10.54
|
|
|
|
10.55
|
|
|
Exhibit
Number
|
|
Description of Document
|
|
|
|
|
Management Contracts/Compensatory Plans or Arrangements
|
10.56†
|
|
|
|
10.57†
|
|
|
|
10.58†
|
|
|
|
10.59†
|
|
|
|
10.60†
|
|
|
|
10.61†
|
|
|
|
10.62†
|
|
|
|
10.63†
|
|
|
|
10.64†
|
|
|
|
10.65†
|
|
|
|
10.66†
|
|
|
|
10.67†
|
|
|
|
10.68†
|
|
|
|
10.69†
|
|
|
|
10.70†
|
|
|
|
10.71†
|
|
|
|
|
|
DGE Acquisition
|
|
10.72
|
|
|
|
|
|
|
Other Exhibits
|
14.1
|
|
|
|
21.1*
|
|
|
|
23.1*
|
|
|
|
23.2*
|
|
|
|
31.1*
|
|
|
|
31.2*
|
|
|
Exhibit
Number
|
|
Description of Document
|
|
32.1**
|
|
|
|
32.2**
|
|
|
|
99.1*
|
|
|
|
101.INS*
|
|
|
XBRL Instance Document.
|
101.SCH*
|
|
|
XBRL Taxonomy Extension Schema Document.
|
101.CAL*
|
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
101.LAB*
|
|
|
XBRL Taxonomy Extension Label Linkbase Document.
|
101.PRE*
|
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
101.DEF*
|
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
Clause 1
|
7
|
|
Definitions
|
7
|
|
Clause 2
|
11
|
|
Address and other particulars of Company
|
11
|
|
Clause 3
|
12
|
|
Duration of Exploration Licence
|
12
|
|
Clause 4
|
13
|
|
Minimum exploration work programme
|
13
|
|
Clause 5
|
16
|
|
Technical Advisory Committee
|
16
|
|
Clause 6
|
18
|
|
Work programme and budget
|
18
|
|
Clause 7
|
18
|
|
Relinquishment
|
18
|
|
Clause 8
|
19
|
|
Discovery and development of Petroleum
|
19
|
|
Clause 9
|
23
|
|
Application for Production Licence
|
23
|
|
Clause 10
|
24
|
|
Sole risk
|
24
|
|
Clause 11
|
26
|
|
Environmental protection
|
26
|
|
Clause 12
|
31
|
|
Work practices and carrying out of operations
|
31
|
|
Clause 13
|
33
|
|
Royalty and annual charges
|
33
|
|
Clause 14
|
34
|
|
Taxation
|
34
|
|
Clause 14A
|
35
|
|
Optional Clause on Participation
|
35
|
|
Clause 15
|
35
|
|
Valuation of Namibian Crude Oil
|
35
|
|
Clause 16
|
38
|
|
Natural gas
|
38
|
|
Clause 17
|
40
|
|
Insurance and assets
|
40
|
|
Clause 18
|
42
|
|
Measurement of petroleum
|
42
|
|
Clause 19
|
42
|
|
Accounts and audits
|
42
|
|
Clause 20
|
43
|
|
ANNEXURE 6
|
91
|
|
PRINCIPLES GOVERNING THE TRAINING SCHEME OF THE MINISTRY OF MINES WAND ENERGY (“MME”)
|
91
|
|
ANNEXURE 7
|
94
|
|
PRINCIPLES GOVERNING THE USE OF FUNDS PAID TO NAMCOR FOR ENVIRONMENTAL STUDIES
|
94
|
|
1.1.
|
In this Agreement, unless the context indicates otherwise:
|
(a)
|
“Affiliate”, in relation to the Company, means any company holding directly or indirectly a majority of shares in the Company or any company which is controlled directly or indirectly by such first-mentioned company;
|
(b)
|
“Agreement” means this Petroleum Agreement between the Government and Signet Petroleum BVI, Cricket Investments (Pty) Ltd and National Petroleum Corporation of Namibia together with the Schedule and Annexures attached to this Agreement, and any extension, renewal or amendment hereof agreed in writing by the Parties;
|
(c)
|
“Appraisal Well” means any Well drilled after a Discovery of Petroleum has been made in the Licence Area for purposes of determining the quantity of Petroleum in the Petroleum Reservoir to which such Discovery relates;
|
(d)
|
“Associated Natural Gas” means Natural Gas produced from any Well in the Licence Area from which Crude Oil is predominantly produced and which is separated from Crude Oil in accordance with Good Oilfield Practices, including the free gas cap, but shall exclude any liquid hydrocarbons extracted from such gas;
|
(e)
|
“Barrel” means 42 United States gallons liquid measure, corrected to a temperature of 60 degrees Fahrenheit;
|
(f)
|
“Block” means a Block, as defined in section 1(1) of the Petroleum Act;
|
(g)
|
“Calendar Month” means any of the 12 months of the Calendar Year;
|
(h)
|
“Calendar Year” means a period of a year commencing on the first day of January in every year;
|
(i)
|
“Commissioner” means the Commissioner defined in section 1(1) of the Petroleum Act;
|
(j)
|
“Company” means the Company which is a Party or, in the case of a joint venture, the Companies which are parties to this Agreement, and includes any other company to which the Company has assigned its interest or any part thereof in relation to its Exploration Licence or in its Production Licence;
|
(k)
|
“Companies Act” means the Companies Act, 2004 (Act No. 28 of 2004);
|
(l)
|
“Crude Oil” means any Petroleum which is in a liquid state at the wellhead or gas-oil separator or which is extracted from Natural Gas in a plant, including distillate and condensate, and which has been produced from the Licence Area;
|
(m)
|
“Crude Oil Produced and Saved” means Crude Oil produced by the Company under a Production Licence, but shall not include any such Crude Oil which has been unavoidably lost or lawfully used in connection with operations for the recovery of Petroleum;
|
(n)
|
“Crystalline Basement”, for purposes of clause 4, means any igneous or metamorphic rock excluding sills, dykes and similar subsurface intrusions or any stratum in and below which the geological structure or physical characteristics of the rock sequence do not have the properties necessary for the accumulation of Petroleum in commercial quantities and which reflects the maximum depth at which any such accumulation can be reasonably expected;
|
(o)
|
“Decommissioning Plan” means the package of measures proposed by the Company pursuant to sA6(2)(viA) of the Petroleum Act to be taken after cessation of production operations to remove or otherwise deal with all installations, equipment, pipelines and other facilities, whether on shore or off shore, erected or used for purposes of such operations and to rehabilitate land disturbed by way of such operations, reviewed pursuant to s.68 A(1) and either approved or revised by the Minister pursuant to s.68A(2) or 68A(3) of the Petroleum Act.
|
(p)
|
“Development Operations” means Development Operations, as defined in section 1 of the Taxation Act;
|
(q)
|
“Development Plan” means the proposed programme of production and of processing of Petroleum submitted in terms of section 46(2) of the Petroleum Act;
|
(r)
|
“Discovery” means a Discovery as defined in section 1 of the Petroleum Act;
|
(s)
|
“Effective Date” means the date on which the last Party signs this Agreement;
|
(t)
|
“End of Period Report” means a report to be submitted by the Company to the Ministry at the end of an Exploration Period;
|
(u)
|
“End of Well Report” means a report to be submitted by the Company to the Ministry at the end of drilling a well;
|
(v)
|
“Environmental Damage” includes any damage or injury to, or destruction of, air or soil or water or any plant or animal life, whether in the sea or in any other water or on, in or under Land;
|
(w)
|
“Exploration Area” means an Exploration Area as defined in section 1(1) of the Petroleum Act;
|
(x)
|
“Exploration Licence” means an Exploration Licence as defined in section 1(1) of the Petroleum Act;
|
(y)
|
“Exploration Operations” means Exploration Operations as defined in section 1(1) of the Petroleum Act;
|
(z)
|
“Exploration Period” means the Initial Exploration Period, the First Renewal Exploration Period or the Second Renewal Exploration Period;
|
(aa)
|
“Exploration Well” means a Well drilled in the course of Exploration Operations, but shall not include an Appraisal Well; “First Renewal Exploration Period” means the period for which the
|
(bb)
|
Exploration Licence issued to the Company has been renewed for the first time under section 34 of the Petroleum Act;
|
(cc)
|
“Good Oilfield Practices” has the meaning assigned to it in section 1(i) of the Petroleum Act;
|
(dd)
|
“immovable Asset” means property which can be touched but which cannot be moved, and includes buildings, fixtures or improvements in or over Land and the right of occupation thereof;
|
(ee)
|
“Inflation Factor” means the figure, expressed to the fourth place of decimals, obtained by dividing the Price Index as reported for the first time in the monthly publication “International Financial Statistics” of the International Monetary Fund in the section “Prices, Production, Employment” for the month in which this Agreement has been signed by the Price Index first so reported for the month in which the expenditure in question has been so incurred or, for purposes of clause 22,4, the month for which the annual adjustment is to be made;
|
(ff)
|
‘Initial Exploration Period” means the period commencing on the date of signature of this Agreement and ending on a date not later than four years as from such first mentioned date or such shorter period as may be determined in clause 3;
|
(gg)
|
“Land” means Land as defined in section 1 (1) of the Petroleum Act;
|
(hh)
|
“Licence Area” means a Licence Area as defined in section 1 of the Taxation Act to which the licence of the Company relates and which is described in Annexure 1 and shown on the map contained in Annexure 2;
|
(ii)
|
“Minister” means the Minister as defined in section 1(1) of the Petroleum Act;
|
(jj)
|
“Ministry’ means the Ministry of Mines and Energy of the Republic of Namibia;
|
(kk)
|
“Namcor” means the National Petroleum Corporation of Namibia;
|
(ll)
|
“Natural Gas” means Natural Gas, whether Associated or Non Associated, and all its constituent elements produced from any Well in the Licence Area and all non hydrocarbon substances therein;
|
(mm)
|
“Natural Gas Produced and Saved” means Natural Gas produced by the Company under a Production Licence, but shall not include any such Natural Gas which has been unavoidably lost or lawfully used in connection with operations for the recovery of Petroleum;
|
(nn)
|
“Non Associated Natural Gas” means Natural Gas other than Associated Natural Gas;
|
(oo)
|
“Party” means the Government or the Company, as the case may be;
|
(pp)
|
“Petroleum” means Petroleum as defined in section 1(1) of the Petroleum Act;
|
(qq)
|
“Petroleum Act” means the Petroleum (Exploration and Production) Act, 1991;
|
(rr)
|
“Petroleum Data” has the meaning assigned to it clause 20.3 of this Agreement;
|
(ss)
|
“Petroleum Field” means a Petroleum Field as defined in section 1(1) of the Petroleum Act
|
(tt)
|
“Petroleum Operations” means Exploration Operations and Production Operations carried out in or in connection with a Licence. Area;
|
(uu)
|
“Petroleum Produced and Saved” means Crude Oil and Natural Gas Produced and Saved;
|
(vv)
|
“Petroleum Reservoir” means a Petroleum Reservoir as defined in section 1(1) of the Petroleum Act;
|
(ww)
|
“Price Index” means the value of the United States Industrial Goods Producer Price Index reported for the first time for the year or, for purposes of clauses 4.7 and 22.5, the month in question in the monthly publication of the International Monetary Fund known as the “International Financial Statistics” in the section titled “Prices, Production, Employment”;
|
(xx)
|
“Production Area” means a Production Area as defined in section 1(1) of the Petroleum Act;
|
(yy)
|
“Production Licence” means a Production Licence as defined in section 1(1) of the Petroleum Act;
|
(zz)
|
“Production Operations” means Production Operations as defined in section 1(1) of the Petroleum Act;
|
(z1)
|
“Quarter” means a period of three consecutive Calendar Months commencing on the first day of January, April, July or October of each Calendar Year;
|
(z2)
|
“Second Renewal Exploration Period” means the period for which the Exploration Licence issued to the Company has been renewed for the second time under section 34 of the Petroleum Act;
|
(z3)
|
“Site Restoration” means all activities required to return a site to its natural state or to render a site compatible with its intended after use after cessation of Petroleum Operations in relation thereto, and shall include removal of equipment, offshore and onshore structures and debris, establishment of compatible contours and drainage, replacement of top soil, re-vegetation, slope stabilization or infilling of excavations;
|
(z4)
|
‘Taxation Act” means the Petroleum (Taxation) Act, 1991;
|
(z5)
|
“Trust Fund” means the trust fund referred to in s.68(B) of the Petroleum Act.
|
(z6)
|
‘Well” means a Well as defined In section 1(1) of the Petroleum Act.
|
1.2.
|
For the purposes of the definition of “Affiliate”‑
|
(a)
|
a Company is directly controlled by any other company or companies if such company or companies hold shares in such first-mentioned Company carrying in the aggregate the majority of votes exercisable at the Company’s general meetings;
|
(b)
|
a particular Company is indirectly controlled by a company or companies (hereinafter referred to as the parent company or companies) if a series of companies can be specified, beginning with the parent company, so related that each company of the series, except the parent company or companies, is directly controlled by one or more of the companies earlier in the series.
|
1.3.
|
The headings to the respective clauses of this Agreement are used merely for convenience and shall not form part of this Agreement.
|
1.4.
|
Unless the contrary intention appears, words importing the masculine gender include females and words in the singular number include the plural, and words in the plural number include the singular.
|
2.1a
|
Signet Petroleum Limited is duly registered and incorporated as a British Virgin Islands company in accordance with the provisions of the companies registration laws of the British Virgin Islands in respect of which incorporation a certificate of incorporation No.1590364 dated 18th June 2010 has been issued.
|
2.1b
|
The registered address of Signet Petroleum Limited is 27, Reid Street, 1st Floor, Hamilton HM11 Bermuda.
|
2.1c
|
Signet Petroleum Limited hereby declares that the following persons are the beneficial owners of more than five per cent of the shares issued by it:‑
|
Full Name:
|
Percentage held:
|
1. Wade Cherwayko
|
1. 70% (seventy percent)
|
2. Ian Burns
|
2. 15% (fifteen percent)
|
3. Middle March Partners
|
3. 15% (fifteen percent)
|
2.2a
|
Cricket investments (Pty) Limited is duly registered and incorporated as a Namibian company in accordance with the provisions of the Companies Act in respect of which incorporation a certificate of incorporation No. _2008 0317.. dated 1 1 th April 2008 has been issued.
|
2.2b
|
The registered address of Cricket Investments (Pty) Limited is 61 Bismarch Street, PO Box 2148 Windhoek Namibia.
|
2.2c
|
Cricket Investments (Pty) Limited hereby declares that the following person is the beneficial owner of more than five per cent of the shares issued by it:‑
|
Full Names:
|
Percentage held:
|
1. C/0 BDO Spencer Accountants
|
1. 100% (one hundred percent)
|
2.3a.
|
National Petroleum Corporation of Namibia is a wholly owned corporation of the Republic of Namibia.
|
2.3b.
|
The registered address of National Petroleum Corporation of Namibia is 1 Avaition Road Road, Petroleum House, Private Bag 13196, Windhoek Namibia
|
2.2c
|
National Petroleum Corporation of Namibia hereby declares that the following person is the beneficial owner of more than five per cent of the shares issued by it:‑
|
Full Names:
|
Percentage held:
|
1. The Republic of Namibia
|
1. 100% (one hundred percent)
|
3.1.
|
Subject to the provisions of the Petroleum Act, the Exploration. ticence:, granted to the Company shall be for an initial period of four years commencing frorn the date of signature of this Agreement by all the parties thereto.
|
3.2.
|
Subject to the provisions of the Petroleum Act, the Exploration Licence referred to in clause 3.1 may be renewed for such further period, not exceeding two years, as may be determined by the Minister at the time of the renewal of such licence as from the date on which such licence would have expired if an application for its renewal had not been made or on the date on which the application for such renewal is granted, whichever date is the later date: Provided that such licence shall not be renewed on more than two occasions.
|
4.1.
|
Subject to clause 4.6, the Company shall, during each of the periods referred to in clauses 4.1(4 4.1(b) and 4.1 (c) below into which its exploration work programme is divided for purposes of this Agreement, carry out the work specified in such paragraphs, and shall spend not less than the amounts so specified in relation to such work:
|
(a)
|
initial Exploration Period
|
(i)
|
Minimum exploration work
|
(A)
|
Gather relevant technical data including drilling seismic, magnetic and gravity data and existing reports relating to the prospectivity for hydrocarbons in the license area;
|
(B)
|
Review all available data on the basin;
|
(C)
|
Reprocess selected seismic lines for reference purposes.
|
(D)
|
Plan for the acquisition of new data, both surface geochemistry and surface seep studies;
|
(E)
|
Acquisition of 3000 km of 2D Seismic Data;
|
(F)
|
Acquisition of 1000 km2 of 3D Seismic Data; and
|
(G)
|
Submission of an End of Period Report to the Ministry, provided that the Parties acknowledge and agree that the
|
(ii)
|
Minimum exploration expenditure
|
(A)
|
US$ 5,000,000 (five million United States Dollars). The Parties acknowledge and agree that this amount:
|
(1)
|
represents the minimum amount to be spent in completing the minimum exploration work stated in clause 4.1(a)(i)•above and it excludes the cost of residential and office accommodation, annual charges payable under clause 13.1(b) and the annual sum to be spent pursuant to clause 22.3; and
|
(2)
|
is expressed in constant price terms at price levels pertaining on the date of signature.
|
(b)
|
First Renewal Exploration Period
|
(i)
|
Minimum exploration work
|
(A)
|
Procure drilling vessel and drill one exploration well to a minimum depth of 3,000 m in the License Area; and
|
(B)
|
Submit End of Well Report to the Ministry.
|
(ii)
|
Minimum exploration expenditure
|
(c)
|
Second Renewal Exploration Period
|
(i)
|
Minimum exploration work
|
(A)
|
Carry out post-drill analysis;
|
(B)
|
Procure a drilling rig;
|
(C)
|
Drill one well to a minimum depth of 3,000 m in the License Area; and
|
(D)
|
Submit End of Well Report to the ministry.
|
(ii)
|
Minimum exploration expenditure
|
4.2.
|
The minimum exploration expenditure referred to in clause 4.1 for each Exploration Period shall not have been satisfied unless the total actual expenditure attributable to the work specified in clause 4.1 for the relevant period equals or exceeds the sums mentioned in the said clause 4.1, provided that for this purpose all such actual
|
4.3.
|
If the Price Index ceases to be published, the Price Index contemplated in clause 4.2 shall for the purposes of this Agreement be such price index as may be determined by mutual agreement between the Parties to this Agreement.
|
4.4.
|
Any expenditure incurred by the Company in respect of an appraisal programme referred to in clause B of this Agreement shall not be regarded to be expenditure incurred for purposes of clause 4.1.
|
4.5.
|
If the Company has during any period referred to in clause 4.1 spent more than the amount specified therein in respect of the period in question, the amount so overspent may, subject to adjustment in terms of clause 4.2, be carried over and credited against the minimum amount so specified in respect of the next ensuing Exploration Period: Provided that this sub clause shall not be construed as detracting or modifying any obligation of the Company to drill Exploration Wells or to conduct seismic surveys in terms of this clause.
|
4.6.
|
No Exploration Well drilled by the Company shall be regarded as discharging the Company from its obligation to drill such Exploration Well, unless
|
(a)
|
such Well has been drilled to a depth or stratigraphic level specified in clause 4.1; or
|
(b)
|
such Well has been drilled to such depth as may be necessary for evaluation of the geological formation established by the available geophysical data as the deepest objective in the feature chosen for drilling; or
|
(c)
|
a Discovery is made and further drilling may cause irrepairable damage to such Discovery; or
|
(d)
|
before reaching the depth referred to in subparagraphs (a) and (b), the Crystalline Basement is encountered; or
|
(e)
|
before reaching such Crystalline Basement, insurmountable technical problems are encountered which will make further drilling impractical, provided that if the said Well is abandoned owing to the said problems before reaching the said Crystalline Basement, the Company shah drill a substitute Exploration Well in the Licence Area to the depth aforesaid and the Parties will agree on an extension of the relevant Exploration Period.
|
4.7.
|
The Company shall within 30 (thirty) days from the Effective Date and on the first day on which the First Renewal Exploration Period and the Second Renewal Exploration Period respectively commence, provide, in a form substantially similar to the form set out in Annexure 3, a bank guarantee in respect of the minimum expenditure referred to in clause 4.1 in respect of the Exploration Period in question and the Parties agree that:
|
(a)
|
The amount of any such bank guarantee shall be reduced at the end of every Quarter by an amount equal to the actual expenditure incurred by the Company during such Quarter in discharge of its obligations under clause 4.1.
|
(b)
|
If at the end of the Initial Exploration Period, the First Renewal Exploration Period or Second Renewal Exploration Period, as the case may be, the expenditure incurred by the Company during any such period, as adjusted in accordance with clause 4.2, and with due regard to any amount carried over in terms of clause 4.5 does not equal or exceed the minimum expenditure referred to in clause 4.1 for such period, the said bank guarantee shall be invoked for purposes of payment to the Minister of the full amount of the shortfall, as adjusted by multiplying such shortfall by a figure, expressed to the fourth place of decimals, obtained by dividing the Price Index, for the Calendar Month immediately preceding the day of receipt of written demand for payment of such shortfall, by such Price Index as so reported for the Calendar Month in which this Agreement has been signed.
|
4.8.
|
The Company shall submit to the Commissioner annually a work programme and a budget reviewed in accordance with the terms of clause 5.4 setting forth the work to be carried out and showing an estimate of the amounts to be spent thereon.
|
5.1.
|
The Minister and the Company shall as soon as possible after the date on which this Agreement is signed establish a committee to be known as the Technical Advisory Committee which shall consist of‑
|
(a)
|
a chairman and three other persons appointed by the Minister: and
|
(b)
|
four other persons appointed by the Company.
|
5.2.
|
The Minister and the Company may, with due regard to the terms of clause 5.1, appoint by notice in writing, whether by telex, telefax or otherwise, any person to act in the place of any member of the Technical Advisory Committee during his absence or incapacity to act as a member of the Committee.
|
5.3.
|
When an alternate member acts in the place of any member he/she shall have the powers and perform the duties of such member.
|
5.4.
|
Without prejudice to the rights and obligations of the Company in relation to the management of its operations the functions of the Technical Advisory Committee shall be‑
|
(a)
|
to oversee and monitor all Petroleum Operations carried out by the Company;
|
(b)
|
to review any proposed exploration work programme and budgets to be submitted by the Company to the Commissioner in terms of clauses 4.8 and
|
(c)
|
to review and recommend to the Commissioner for approval, at any date after the date on which application is made by the Company for a Production Licence in respect of any part of the Licence Area and for as long as Petroleum is produced in such area, any proposed exploration work programme and budgets and any proposed amendment to be submitted to the Commissioner in terms of clauses 4.8 and 6;
|
(d)
|
to review any appraisal programmes submitted by the Company to the Minister in terms of clause 8 and any Development Plan which the Company proposes to submit in connection with an application for a Production Licence in terms of clause 9;
|
(e)
|
to ensure that the accounting of expenditure and the maintenance of operating records and reports kept in connection with the Petroleum Operations are made in accordance with this Agreement and the accounting principles and procedures generally accepted in the international petroleum industry.
|
5.5.
|
All meetings of the Technical Advisory Committee shall be held at such places, whether within or, with the prior approval in writing of the Minister, outside Namibia, and at such times, but not less than one meeting during each half of the Calendar Year during the term of the Exploration Licence and thereafter not less than one meeting during each Quarter, as may be determined unanimously by its members.
|
5.6.
|
Five members of the Technical Advisory Committee shall form a quorum for a meeting of the Committee.
|
5.7.
|
The Minister or the Company shall have the right to call any expert to any meeting of the Technical Advisory Committee to advise the Committee on any matter of a technical nature requiring expert advice.
|
5.8.
|
A unanimous vote of all the members of the Technical Advisory Committee present at a meeting thereof on any matter requiring a decision of the Committee as set out in clause 5.4 shall be a decision of the Committee and shall be binding upon the Parties to this Agreement. The committee shall not make any decision which shall unreasonably or negatively impede the Company’s ability to fulfill its obligations under this Agreement.
|
5.9.
|
If a decision cannot be taken as contemplated in clause 5.8
|
(a)
|
in the case of a proposal of the Company in relation to a matter referred to in paragraph (a), (b) or (d) of clause 5.4, the proposal of the Company shall prevail, provided (i) that such proposal is not inconsistent with any term of this Agreement; and (ii) that, in the case of the review of a Development Plan, such proposal contains the particulars contemplated in section 46(2)(e) to (k) of the Petroleum Act;
|
(b)
|
in the case of any dispute in respect of a matter contemplated in paragraph
|
(c)
|
of clause 5.4, such dispute between the Minister and the Company shall be referred, within 90 days as from the date of the meeting on which no decision could have so been taken, to a sole expert appointed in accordance with the terms of clause 29.6.
|
6.1.
|
During the currency of an Exploration Licence the Company shall prepare and submit in each Calendar Year, not less than three months prior to the last day of each Calendar Year to the Commissioner a work programme and budget referred to in paragraph (b) or (c) of clause 5.4 for review or for review and recommendation by the Technical Advisory Committee in accordance with the terms of those paragraphs, setting forth the Exploration Operations which the Company proposes to carry out during the period of 12 months immediately following such last day and the estimated cost thereof.
|
6.2.
|
Any work programme and budget submitted in terms of sub clause 6.1 for review or review and recommendation by the Technical Advisory Committee to the Commissioner and any revision or amendment thereof shall be consistent with the requirements set out in clause 4 relating to the minimum exploration work and minimum exploration expenditure for any of the periods so set out within which the work programme and budget will fall.
|
6.3.
|
The Company may by notice in writing to the Minister amend any work programme or budget submitted to the Technical Advisory Committee, provided that the work programme or budget is not required to be submitted to that Committee for review and recommendation to the Commissioner under the terms of paragraph (c) of clause 5.4 and such amendment is consistent with the Company’s obligations under clause 4.
|
6.4.
|
A notice referred to in clause 6.3 shall state the reasons for which the amendment is necessary or desirable.
|
7.1.
|
Subject to the provisions of the Petroleum Act, the Company shall by notice in writing addressed and delivered to the Commissioner relinquish‑
|
(a)
|
not later than 30 days before the end of the fourth year of the currency of the Exploration Licence, at least 50 per cent of the Exploration Area as described in Annexure 1 to which such licence relates and identified in such notice;
|
(b)
|
not later than 30 days before the end of the sixth year of such currency, at least a further 26 per cent of such Exploration Area as described in Annexure 1 and so identified,
|
(i)
|
if such licence is cancelled in terms of section 19(3) of the Petroleum Act in relation to any area of Land in any Calendar Year of the currency of such licence, such area of Land shall be deemed to have been relinquished for the purposes of the determination of the relinquishment next required to be made by the Company under paragraph (a) or (b);
|
(ii)
|
any area of Land relinquished under clause 7.2, shall be deemed to have been relinquished for the purposes of the determination of the relinquishment next required to be made by the Company under paragraph (a) or (b);
|
(iii)
|
the Company shall relinquish such Land in such a manner so as to ensure that the Exploration Area is, after such relinquishment, a single area consisting, in so far as it is possible, of rectangular blocks bounded by lines running either due North and South or due East and West and having sides, each of at least 30 seconds of longitude or latitude, as the case may be;
|
(iv)
|
the Company shall not be required to relinquish any Land in the Exploration Area which is subject to an application for a Production Licence or situated within a Petroleum Field or subject to an application for the declaration of a Petroleum Field.
|
7.2.
|
The Company may, subject to the terms of sub-paragraph (iii) of the proviso to clause 7.1, by notice in writing addressed and delivered to the Commissioner- relinquish any area of Land to which its Exploration Licence relates from a date not less than six months from the date on which such notice was delivered to the Commissioner.
|
7.3.
|
Any relinquishment in terms of clause 7.2 shall be without prejudice to any obligation incurred by the Company in respect of the area relinquished prior to the date of relinquishment and such relinquishment shall not affect the obligations of the Company under clause 4.
|
8.1.
|
When a Discovery is made in an Exploration Area, the Company shall
|
(a)
|
forthwith inform the Commissioner by notice in writing of the fact that such Discovery has been made;
|
(b)
|
forthwith cause tests to be made in connection with such Discovery in order to determine the commercial interest of such Discovery;
|
(c)
|
within a period of 60 days after such notice, furnish the Commissioner in writing with particulars of the steps which it proposes to take to satisfy the requirements of paragraph (e) of this clause;
|
(d)
|
within a period of 60 days after such notice, furnish the Commissioner in writing with particulars relating to the Block or Blocks where such Discovery has been made, the nature of such Discovery and such other particulars as the Commissioner may require;
|
(e)
|
within a period of 60 days after having completed such tests, furnish the Commissioner with a report containing an evaluated result of such tests and an evaluation of the potential commercial interest of such Discovery.
|
8.2.
|
If the report referred to in paragraph (e) of clause 8.1 indicates that in the Company’s judgment, utilizing Good Oilfield Practices, a Discovery may be of commercial interest, the Company
|
(a)
|
shall within 90 days of the delivery of such report address and deliver to the Commissioner an appraisal programme which is commensurate with the size and nature of the Discovery for the Commissioner’s approval which shall include particulars relating to the drilling of Appraisal Wells;
|
(b)
|
shall upon approval forthwith take all such steps as may be reasonable in the circumstances in order to appraise the Discovery and determine the quantity of Petroleum to which the Discovery relates in so far as it occurs within the Exploration Area;
|
(c)
|
may apply, pursuant to section 42 of the Petroleum Act, for the declaration of a Petroleum Field over the relevant area;
|
8.3.
|
The Commissioner shall by notice in writing addressed and delivered to the Company within 30 days of delivery of the appraisal programme indicate whether or not he approves thereof.
|
8.4.
|
Where the appraisal programme is not approved by the Commissioner, the Technical Advisory Committee shall, within a period of 30 days from the date on which the notice referred to in clause 8.3 was delivered to the Company, meet to discuss and agree on revisions to the appraisal programme.
|
8.5.
|
If the members of the Technical Advisory Committee are unable to agree on revisions to the appraisal programme, the provisions of clause 5.9 shall apply mutatis mutandis, enabling the Company to proceed with the implementation of its appraisal programme, with such revisions, if any, as it deems fit. The Company’s appraisal programme shall be deemed to have been approved by the Commissioner on the date on which the Commissioner receives notification from the Technical Advisory Committee on the outcome of its deliberations.
|
8.6.
|
The Company shall, within two years from the date on which the Commissioner approved of the appraisal programme or such longer period as the Commissioner on• good cause shown may allow, address and deliver to the Commissioner‑
|
(a)
|
a full report containing particulars of the results of the appraisal programme, including particulars relating to
|
(i)
|
the location and depth of Petroleum or hydrocarbon bearing structures;
|
(ii)
|
the composition of Petroleum or hydrocarbons;
|
(iii)
|
the estimated recoverable reserves of Petroleum or hydrocarbons;
|
(iv)
|
the estimated daily production potential of Petroleum or hydrocarbons;
|
(b)
|
a preliminary estimate of the cost of Development Operations and Production Operations relating to the Discovery, including the cost of transportation of Petroleum or hydrocarbons, based upon an outline design for the development of the Discovery.
|
8.7.
|
The Company shalt, in so far as it is able to do so from results obtained from an appraisal programme, within 13 months after the date on which the Commissioner approved of such programme, issue an interim report containing the particulars and preliminary estimates contemplated in clause 8.6.
|
8.8.
|
The Commissioner may, at any time after delivery of the report and estimates referred to in clause 8.6, request the Company to supply such further particulars relating to such report as he deems necessary and the Company shall comply in writing with such request within 30 days from the date of delivery of such request.
|
8.9.
|
The Commissioner and the Company shall, within three months of the delivery of the report and estimates referred to in clause 8.6 or such longer period as the Commissioner on good cause shown may allow, discuss the report and estimates to determine whether the Discovery is of commercial interest.
|
8.10.
|
If the Company decides that the Discovery is not of present commercial interest and the Commissioner does not agree with such determination, the Commissioner may cause an independent evaluation of the Discovery to be carried out. If the independent evaluation establishes that the Discovery is of commercial interest, the provisions of clause 8.11 shall apply.
|
8.11.
|
If the conclusion of the evaluation referred to in clause 8.10 is that the Discovery is of commercial interest the Minister may, subject to the terms of clause 8.12, by notice in writing addressed and delivered to the Company, direct that with effect from a date specified in such notice the Licence in question shall cease to be of any force and effect in relation to the Discovery Block in question and any adjoining Land required for purposes of obtaining access to that Block.
|
8.12.
|
The Minister shall not exercise his powers under clause 8.11, unless he‑
|
(a)
|
has submitted the evaluation referred to in clause 8.10 to the Company for consideration and afforded the Company a period of three months from the date of delivery of the said evaluation to review its position regarding the commercial interest of the Discovery and to notify the Minister in writing of its
|
(b)
|
has by notice in writing addressed and delivered to the Company informed the Company of his intention to exercise such powers;
|
(c)
|
has requested the Company to make representations to the Minister in relation to the matter on or before a date specified in such notice;
|
(d)
|
is, having regard to information available to him and after having considered any representations made to him by virtue of the notice referred to in paragraph (a), satisfied that the Discovery is of commercial interest.
|
8.13.
|
In the event of the Company notifying the Minister of its intention to develop the Discovery as contemplated in paragraph (a) of clause 8.12, the Company shall reimburse the Government the cost of the independent evaluation referred to in clause 8.10.
|
8.14.
|
If the Minister has given a direction to the Company that the Company’s Exploration Licence shall cease to be of any force and effect in relation to the Discovery Block in question and any adjoining Land required for purposes of obtaining access to that Block in terms of clause 8.11, the Company may apply to the Minister to reinstate the rights it previously had in respect of the relevant area: Provided that‑
|
(a)
|
the rights so reinstated shall not subsist beyond the date on which they would have expired, if the Minister had not made the direction under the said clause 8.11;
|
(b)
|
no such rights shall be exercised by the Company if the Minister has, subsequent to the said direction, granted any rights to any other person in relation to the area in question which are inconsistent with the rights so reinstated by the Minister;
|
(c)
|
the Company pays to the Government an amount equal to‑
|
(i)
|
the cost of the independent evaluation referred to in clause 8.10, if any;
|
(ii)
|
any expenditure incurred by the Government in relation
|
(iii)
|
500 per cent of all such expenditure referred to in subparagraphs (i) and(ii), which amount shall not be allowable as a deduction under the Taxation Act.
|
8.15.
|
Notwithstanding the other provisions of this clause 8, if after having carried out an appraisal programme pursuant to section 39 (2) of the Petroleum Act, that a Discovery of Crude Oil is not of present commercial interest but may become of commercial interest then, if the Commissioner agrees with such determination, the Minister hereby agrees to allow the Company to retain the Discovery Block for the duration of the Company’s Exploration Licence and any renewal thereof, provided that:
|
(a)
|
The determination of potential commerciality shall be based on relevant economic criteria, including but not limited to, potential Crude Oil production rates, Crude Oil prices, development costs, operating costs as well as any other relevant criteria;
|
(b)
|
The Company shall reassess the commerciality of the Discovery twelve months after the Discovery has been notified to the Commissioner and thereafter every two years, based on the same economic criteria as set forth in (a) above;
|
(c)
|
The Company shall within 30 days after the completion of each reassessment inform the Minister whether it determines the Discovery still to be of potential commercial interest. A copy of any reassessment study shall be given to the Commissioner;
|
(d)
|
If as a result of the Company’s reassessment under clause 8.15(b) the Company determines that the Discovery has become of commercial interest the provisions of clause 8.2 to 8.14 shall apply;
|
(e)
|
If as a result of the Company’s reassessment under clause 18.5(b) the Company determines that the Discovery remains only of potential commercial interest, but the Commissioner considers that it is of present commercial interest, the provisions of clause 8.10 shall apply; and
|
(f)
|
If as a result of the Company’s reassessment under clause 8.15(b), the Company determines that the Discovery is no longer of potential commercial interest, the Minister may require the Company to relinquish the Discovery Block.
|
9.1.
|
If the Company intends to apply for a Production Licence in respect of the Discovery Block in question as contemplated in section 43(1) of the Petroleum Act, the Company shall arrange a meeting with the Commissioner to identify, after having had due regard to all the relevant particulars, the Discovery Block or Blocks to which such licence should relate.
|
9.2.
|
Where a part of a Petroleum Reservoir in respect of which the Company intends to make an application for a Production Licence is contained in a Block or Blocks outside the Licence Area, such Block or Blocks may be included at the Minister’s discretion in the area in relation to which application for a Production Licence is made, provided
|
9.3.
|
The Company shall, in making an application for a Production Licence as contemplated in section 43(1) of the Petroleum Act, comply with the provisions of section 46(2) of the Petroleum Act and any other provisions relating to such applications.
|
9.4.
|
The proposed programme of Production Operations and processing of Petroleum referred to in section 46(2)(i) of the Petroleum Act shall‑
|
(a)
|
relate exclusively to the Block or Blocks within the area to which the Licence relates and which, on a reasonable interpretation of the available particulars, contain a Petroleum Reservoir or part thereof;
|
(b)
|
be designed to ensure the most efficient, beneficial and timely use of the Petroleum resources in the area to which the Production Licence relates; and
|
(c)
|
be compiled in accordance with sound engineering, economic, safety and environmental principles recognized in the international petroleum industry.
|
9.5.
|
The Minister shall, subject to the provisions of section 47 of the Petroleum Act and after approval of the Development Plan, within six months after delivery of the application for a Production Licence referred to in clause 9.3, grant such application and issue such licence for a period of 25 years
|
9.6.
|
If, within a period of 60 days after submission of the Development Plan, the Minister has failed or refused to approve such Development Plan, the Minister shall arrange a meeting with the Company to be held within a period of 14 days after the expiry of the aforesaid period,
|
9.7.
|
If the Minister and the Company are unable to agree at the meeting referred to in clause 9.6 on whether such Development Plan meets the requirements set forth in clause 9.4, the Minister or the Company may request the appointment of the expert contemplated in clause 29.6, if necessary, and submit the dispute for determination.
|
9.8.
|
In the event of the expert referred to in clause 9.7 determining that such Development Plan does not meet the requirements of clause 9.4, the said expert shall determine which modifications to such Development Plan are necessary to comply with the requirements of clause 9.4 and the Company shall modify such Development Plan accordingly.
|
9.9.
|
The decision of the expert referred to in clause 9.8 shall be final and binding on the Minister and the Company, provided that in the event of the Company being dissatisfied with the decision of the said expert, it may, within 60 days after the
|
9.10.
|
date on which the decision was conveyed to it, notify the Minister that it withdraws the application for a Production Licence referred to in clause 9.3, in which event such notice shall be deemed to be a report by the Company contemplated in section 39(1) of the Petroleum Act.
|
10.1.
|
Subject to the terms of clause 10.5, the Minister may during any Exploration Period require the Company by notice in writing‑
|
(a)
|
to test any additional horizons within the agreed Well depth; or
|
(b)
|
to penetrate and test any horizons deeper than such depth; or
|
(c)
|
to continue drilling and test any such additional horizons.
|
10.2.
|
A notice referred to in clause 10.1 shall be given as early as possible prior to or during the drilling of the Well, but in any case not after the Company has notified the Minister of the detailed completion or abandonment plan for the Well. Upon receipt of such notice the Company shall, subject to the terms of clause 10.5, cause such tests, penetration and drilling to be carried out at the sole cost and risk of the Government. At any time before such tests, penetration or drilling is carried out the Company may elect to include such tests, penetration or drilling in its Exploration Operations.
|
10.3.
|
Subject to the terms of clause 10.5, the Minister may‑
|
(a)
|
during any Exploration Period recommend that the Company include certain Exploration Wells in its exploration work programme;
|
(b)
|
if any dispute arises in relation to any recommendation made in terms of paragraph (a), require by at least six months notice in writing to the Company, which notice shall contain the proposed location of the Well, the geological objective and other details of the Well to be drilled and the schedule of financing, the Company to drill within the Exploration Area and at the sole cost and risk of the Government, a maximum of two such Exploration Wells per Calendar Year, provided that suitable rigs are available for use in the Exploration Area, and such operations will not unreasonably interfere with Petroleum Operations required to be carried out under this agreement. The Company may, at any time before such Exploration Wells are drilled, elect to include such Exploration Wells in its Exploration Operations.
|
10.4.
|
If a Discovery is made in consequence of any activities carried out in terms of clauses 10.1 and 10.3 the Minister may cause at the sole cost, risk and benefit of the Government the Discovery to be appraised and any Petroleum discovered to be developed and produced. The Company may before such appraisal, development or production, as the case may be, inform the Minister by notice in writing that it wishes to take over such appraisal or development under the terms of its Licence. In such event the Company shall pay to the Government
|
(a)
|
within 30 days from the date of dispatch of its notice to the Minister, an amount equivalent to the expenditures incurred by the Minister in connection with such appraisal, development or production; and
|
(b)
|
if the Company so informs the Minister before such appraisal commences, an additional amount equal to 200 per cent of the expenditure referred to in paragraph (a) or, if the Company so informs the Minister after such appraisal has commenced, but before such development commences, an additional amount equal to 600 per cent of the expenditure referred to in paragraph (a), which expenditure and additional amount shall not be allowable as a deduction under the Taxation Act.
|
10.5.
|
The Company shall by virtue of a notice given in terms of clauses 10.1, 10.3 and 10.4 not be required‑
|
(a)
|
to test any additional horizons or to penetrate and test any deeper horizons or to drill any additional Exploration Wells if, employing Good Oilfield Practices, such operations are not technically feasible and cannot be conducted in a safe and prudent manner or such operations will have a detrimental effect on the proper performance of the Company’s work programme;
|
(b)
|
to penetrate and test horizons deeper than the agreed Well depth, if the Weil in question has encountered productive horizons;
|
(c)
|
to drill Exploration Wells in a Petroleum Field or a Production Area or a Discovery Block retained pursuant to clause 16.12;
|
(d)
|
to carry out any operations referred to in such notice during any Calendar Month, unless the Government advances, subject to such conditions of accounting as the Minister may determine, before the commencement of such Calendar Month, to the Company an amount to finance the expenditure to be incurred in connection therewith.
|
10.6.
|
The Minister shall not engage any third party to carry out any activities contemplated in clause 10.4, unless he has first offered by notice in writing the Company the right to carry out such activities on the Government’s behalf, on the same terms agreed to by such third party and the Company has refused the offer or has failed to accept such offer within a period of 60 days as from the date on which the offer was made and unless such activities will not interfere with Petroleum Operations to be carried out pursuant to this Agreement.
|
11.1.
|
The Minister and the Company concede that Petroleum Operations will cause some impact on the environment in the Licence Area.
|
11.2.
|
The Company shall‑
|
(a)
|
conduct its Petroleum Operations in a manner likely to conserve the natural resources of Namibia and protect the environment;
|
(b)
|
employ the best available techniques in accordance with Good Oilfield Practices for the prevention of Environmental Damage to which its Petroleum Operations might contribute and for the minimization of the effect of such operations on adjoining or neighboring Lands; and
|
(c)
|
implement the proposals contained in its Development Plan regarding the prevention of pollution, the treatment of wastes, the safeguarding of natural resources and the progressive reclamation and rehabilitation of Lands disturbed by Petroleum Operations.
|
11.3.
|
The Company undertakes for purposes of this Agreement to take all reasonable, necessary and adequate steps in accordance with Good Oilfield Practices to minimize Environmental Damage to the Licence Area and adjoining or neighboring Lands.
|
11.4.
|
If the Company fails to comply with the terms of clause 11.3 or contravenes any law on the prevention of Environmental Damage and such failure or contravention results in any Environmental Damage, the Company shall take all necessary and reasonable measures to remedy such failure or contravention and the effects thereof.
|
11.5.
|
If the Minister has reason to believe that any works or installations erected by the Company or any operations carried out by the Company are endangering or may endanger persons or any property of any other person or is causing pollution or is harming wildlife or the environment to a degree which the Minister deems unacceptable, the Minister may require the Company to take reasonable remedial measures within such reasonable period as may be determined by the Minister and to take reasonable and appropriate steps to repair any damage to the environment. If the Minister deems it necessary, he may require the Company to discontinue Petroleum Operations in whole or in part until the Company has taken such remedial measures or has repaired any damage.
|
11.6.
|
The measures and methods to be used by the Company for purposes of complying with the terms of clause 11.3 shall be determined in timely consultation with the Minister upon the commencement of Petroleum Operations or whenever there is a significant change in the scope or method of carrying out Petroleum Operations, and the Company shall take into account the international standards applicable in similar circumstances and the relevant environmental impact assessment studies carried out in accordance with clause
|
11.7.
|
The Company shall notify the Minister in writing of the nature of the measures and methods finally determined by the Company and shall cause such measures and methods to be reviewed from time to time in view of prevailing circumstances.
|
11.8.
|
The Company shall cause a person or persons, approved by the Minister on account of their special knowledge of environmental matters, to carry out two environmental impact assessment studies, in order
|
(a)
|
to determine the prevailing situation relating to the environment, human beings, wildlife or marine life in the Licence Area and in the adjoining or neighboring areas at the time of the studies; and
|
(b)
|
to establish what the effect will be on the environment, human beings, wildlife or marine life in the Licence Area in consequence of the Petroleum Operations to be made under this Agreement, and to submit for consideration by the Parties measures and methods contemplated in clause 11.6 for minimizing Environmental Damage and carrying out Site Restoration in the License Area.
|
11.9.
|
The first of the two studies referred to in clause 11.8 shall be carried out in two parts. The first part of the first study shall be a baseline study of existing information on the environment, human beings, wildlife or marine life in the Licence Area. The company shall conclude such baseline study prior to undertaking any fieldwork for a seismographic survey. The second part of the first study shall be an environmental impact assessment study of the effects of drilling on the environment. This environmental impact assessment study is to be concluded sufficiently in advance of the commencement of drilling to enable the results of this environmental impact assessment study to be taken into account in preparing all relevant drilling management, waste management and contingency plans relating to the exploration drilling stage. A minimum of 12 copies of the reports on the baseline and environmental Impact assessment studies shall be submitted to the Government.
|
11.10.
|
The second of the two studies referred to in clause 11.8 shall be an environmental impact assessment study of the effects of production on the environment and shall be concluded sufficiently in advance of the commencement of Production Operations to enable the results of this environmental impact assessment study to be taken into account in preparing all relevant production management, waste management and contingency plans relating to Production Operations and shall be submitted by the Company as part of its Development Plan. A minimum of 12 copies of the report on the environmental impact assessment study shall be submitted to the Government.
|
11.11.
|
The studies mentioned in clause 11,8 shall contain proposed environmental guidelines to be followed in order to minimize Environmental Damage and shall include, but riot be limited to‑
|
(a)
|
access cutting;
|
(b)
|
clearing and timber salvage;
|
(c)
|
wildlife and habitat protection;
|
(d)
|
marine resource protection;
|
(e)
|
fuel storage and handling;
|
(f)
|
use of explosives;
|
(g)
|
camps and staging areas;
|
(h)
|
liquid and solid waste disposal;
|
(i)
|
cultural and archaeological sites;
|
(j)
|
selection of drilling sites;
|
(k)
|
terrain stabilization;
|
(l)
|
blowout prevention plan;
|
(m)
|
combating oil spills;
|
(n)
|
flaring during completion and testing of gas and oil wells;
|
(o)
|
Well abandonment;
|
(p)
|
rig dismantling and site completion;
|
(q)
|
reclamation for abandonment; and
|
(r)
|
noise control.
|
11.12.
|
The Company shall ensure‑
|
(a)
|
that Petroleum Operations are carried out in an environmentally acceptable and safe manner consistent with Good Oilfield Practices and that such operations are properly monitored;
|
(b)
|
that the pertinent completed environmental impact assessment studies are made available to its employees and to its contractors to develop adequate and proper awareness of the measures and methods of environmental protection to be used in carrying out its Petroleum Operations; and
|
(c)
|
that any agreement entered into between the Company and its contractors relating to its Petroleum Operations shall include the terms set out in this Agreement and any established measures and methods for the implementation of the Company’s obligations in relation to the environment under this Agreement
|
11.13.
|
The Company shall, before carrying out any drilling, prepare and submit for review by the Minister an oil spill and fire contingency plan designed to achieve rapid and effective emergency response in the event of an oil spill or fire.
|
11.14.
|
In the event of‑
|
(a)
|
an emergency or accident arising from Petroleum Operations affecting the environment, the Company shall forthwith notify the Minister accordingly;
|
(b)
|
any fire or oil spill, the Company shall promptly implement the relevant contingency plan;
|
(c)
|
any other emergency or accident arising from the Petroleum Operations affecting the environment, the Company shall take such action as may be
|
11.15.
|
If the Company fails to comply with any terms contained in clause 11 within a period determined by the Minister under any such term, the Minister may, after giving the Company reasonable notice, take any action which may be necessary to ensure compliance with such term, and recover, immediately after having taken such action, all expenditure incurred in connection with such action from the Company together with such interest as may be determined in accordance with paragraph 6.2 of Annexure 4 to this Agreement.
|
11.16.
|
If the Company or the operator for the Company has already completed and submitted to the Government reports on the studies referred to in clause 11.8 for a previous Exploration Licence held in Namibia in the 5-year period preceding the application for this Exploration Licence and those studies either
|
(a)
|
are sufficiently broad ranging to encompass clearly the present Licence Area, or
|
(b)
|
do not encompass the present Licence Area but a baseline study and environmental impact assessment study have been submitted by the holder of an Exploration Licence covering an area near the present Licence Area the Company may in a case falling within (a) above, submit the reports on the studies for such previous Licence in fulfillment of the requirements of clauses 11.9 and 11.10 relating to exploration drilling and, in a case falling within (b) above submit such environmental impact assessment submitted by the said holder of an Exploration Licence, with any modifications which the Company wishes to make; provided that:
|
(i)
|
in response to a written request from the Company, the Minister approves in writing the course of action selected from (a) or (b) above;
|
(ii)
|
In response to a written request from the Company directed through the Ministry of Mines and Energy, The Ministry of Fisheries and Marine Resources, the Ministry of Environment and Tourism, the Ministry of Works, Transport and Communication and the Ministry of Health and Social Services also approve in writing the course of action selected from (a) or (b) above;
|
(iii)
|
The company that carried out the baseline study and environmental impact assessment study which are to be submitted in terms of (b) above agrees to this course of action;
|
(iv)
|
The baseline study and the environmental impact assessment study submitted in terms of (b) above encompass the present Licence Area;
|
(v)
|
Fluids, muds and chemicals to be used during drilling are the same as those used in the Exploration Licence covered by the environmental impact assessment study submitted;
|
(vi)
|
Oil spill drift simulation studies and any other special studies relevant to an environmental impact assessment of the effect of drilling on the environment in the present Licence Area as may be required by the Minister are carried out and the results thereof together with plans for mitigating actions be submitted in the form of reports to the Government. A minimum of 12 copies of these reports are to be submitted;
|
(vii)
|
The results of the resubmitted environmental impact assessment study as well as the studies conducted under (v) above are taken into account in preparing ail relevant drilling management, waste management and contingency plans relating to the exploration drilling stage;
|
(viii)
|
An amount equal to half the average cost of the three most recent baseline and environmental impact assessment studies complying with the requirements of the first of the studies in clause 11.8 for offshore oil exploration in Namibia or such other amount as may be agreed between the Parties is paid to the National Petroleum Corporation of Namibia (NAMCOR). This money shall be used by NAMCOR in accordance with the principles laid out in Annexure 7 in order to collect offshore environmental data relevant to oil exploration and production in Namibia. Projects to be undertaken by NAMCOR in this connection shall be decided upon in consultation with the oil exploration companies operating in Namibia and with the Ministries of Fisheries and Marine Resources and the Environment and Tourism.
|
11.17.
|
The Company shall on the expiration or termination of this Agreement or on relinquishment of part of the Licence Area‑
|
(a)
|
subject to clause 17, remove or otherwise deal with, as directed by the Minister in consultation with the Minister or Ministers responsible for environment, fisheries and finance, all equipment and installations from such Licence Area or relinquished area to the extent and in the manner agreed with the Minister in terms of the Decommissioning Plan approved by the Minister pursuant to s.68A(2) of the Petroleum Act;
|
(b)
|
subject to clause 17, remove, or otherwise deal with, as directed by the Minister in consultation with the Minister or Ministers responsible for environment, fisheries and finance, all installations, equipment, pipelines and other facilities erected or used outside the Licence Area for the petroleum operations; and
|
(c)
|
perform all necessary Site Restoration activities in accordance with Good Oilfield Practices and shall take all other action necessary to prevent hazards to human life or to the property of others or the environment.
|
11.18.
|
The Company shall on the date referred to in s.68B(1) of the Petroleum Act establish a Trust Fund in accordance with the provisions of s.68(B) of the said Act for the purpose of decommissioning facilities on cessation of production operations.
|
12.1.
|
The Company shall conduct Petroleum Operations in the Licence Area
|
(a)
|
subject to the provisions of the Petroleum Act;
|
(b)
|
in accordance with Good Oilfield Practices;
|
(c)
|
diligently, expeditiously, efficiently and in a proper, safe and workmanlike manner;
|
(d)
|
in accordance with work programmes reviewed or approved in terms of the Petroleum Act and this Agreement.
|
12.2.
|
The Company shall ensure that all equipment, materials, supplies, plant and installations used by the Company, its contractors and subcontractors comply with generally accepted standards in the international petroleum industry and are of proper construction and kept in good working order.
|
12.3.
|
The Company shall, within 90 days after the date on which this Agreement was signed, appoint
|
(a)
|
a General Manager to manage the Petroleum Operations in the Licence Area and who shall be authorised to take such steps as may be necessary in accordance with the provisions of the Act and the terms and conditions of this Agreement to carry out the Petroleum Operations on behalf of the Company; and
|
(b)
|
a Deputy General Manager to manage such operations in the absence of the General Manager, who shall be resident in Namibia, and shall be technically competent and sufficiently experienced to manage such operations.
|
12.4.
|
The Company shall, within 30 days after the appointment of the General Manager or Deputy General Manager referred to in clause 12.3, notify the Commissioner in writing of their identity and respective addresses.
|
12.5.
|
Where the Company consists of more than one Company‑
|
(a)
|
all the terms and obligations of this Agreement shall apply to each one of such companies jointly and severally;
|
(b)
|
Signet Petroleum Limited shall be deemed to be the operator and Company who shall carry on the Petroleum Operations of the Company under this Agreement, unless the Commissioner pursuant to an application in writing addressed and delivered to him approves a change of operator, in which event the other operator so approved of shall be deemed to be the operator from the date of such approval;
|
(c)
|
any operating or other agreement relating to the Petroleum Operations entered into by or between such companies shall be consistent with the provisions of this Agreement and shall be in writing and a copy of each such agreement shall
|
12.6.
|
All individual services to be performed or materials and equipment to be purchased for or in connection with the Petroleum Operations which cost in excess of US $500,000 (or the equivalent thereof as expressed in Namibian Dollars) shall be contracted for by the Company only after competitive quotations have been called for and on the basis therof.
|
12.7.
|
The Company shall ensure adequate compensation for injury to persons or damage to property caused by its Petroleum Operations under this Agreement.
|
13.1.
|
Subject to the provisions of the Petroleum Act, the Company shall pay
|
(a)
|
Quarterly on or before the last day of each Calendar Month following each Quarter, for the benefit of the State Revenue Fund, a royalty of 5 per cent on the market value of Petroleum Produced and Saved in the Production Area during each Quarter, determined‑
|
(i)
|
in the case of Crude Oil, in accordance with the terms of clause 15; and
|
(ii)
|
in the case of Natural Gas, in accordance with the terms of clause 16.7;
|
(b)
|
on the date of the issue of the Exploration Licence or Production Licence, and thereafter annually on or before the last day of the Calendar Month during which every period of 12 months of the currency of such Licence expires, for the benefit of the State Revenue Fund, an annual charge, equal to the figure expressed in Namibian Dollars, calculated by multiplying the number of square kilometers included in the Block or Blocks to which the Licence relates
|
(i)
|
in the case of an Exploration Licence
|
(c)
|
by 60 during the period of the licence determined or extended in terms of paragraph (a) of subsection (1) or paragraph (a) of subsection (2A) of section 30 of the Petroleum Act;
|
(d)
|
by 90 during the period of the licence determined or extended in terms of paragraph (b) of subsection (1) or paragraph (b) of subsection (2A) of section 30 of the Act in respect of the first renewal of the licence;
|
(e)
|
by 120 during the period or periods of the licence determined or extended in terms of paragraph (b) of subsection (1) or paragraph (b) of subsection (2A) of section 30 of the Act in respect of the second renewal of the licence;
|
(f)
|
by 150 during the subsequent period or periods of the licence determined or extended in terms of paragraph (b) of subsection (1), read with paragraph (b)
|
(i)
|
in the case of a Production Licence, by 1500.
|
13.2.
|
The Company shall, no later than one Calendar Month after the end of each Quarter, submit to the Minister and to the Permanent Secretary: Finance in such form as may be specified by the Minister, a statement containing particulars of‑
|
(a)
|
the quantity of Crude Oil and Natural Gas Produced and Saved from each Production Area during such Quarter;
|
(b)
|
the market value F.O.B. Namibia of the Crude Oil and the market value of the Natural Gas on which royalty is payable;
|
(c)
|
the amount of royalty payable for that Quarter;
|
(d)
|
the calculation of such amount: and
|
(e)
|
any other matters which the Minister or the Permanent Secretary: Finance may from time to time require.
|
14.1.
|
The Company shall pay annually, for the benefit of the State Revenue Fund, a petroleum income tax referred to in section 5 of the Taxation Act and an additional profits tax referred to in section 19 of that Act to be determined in accordance with the provisions of that Act and the terms of clause 14.2 and clause 14.3 of this Agreement
|
14.2.
|
The rate at which additional profits tax shall be levied on the Company under section 21(b)(ii) of the Taxation Act in relation to the second accumulated net cash position shall be 7.5 per cent.
|
14.3.
|
The rate at which additional profits tax shall be levied on the Company under section 21 (c)(ii) of the Taxation Act in relation to the third accumulated net cash position shall be 10 per cent,
|
14.4.
|
Subject to the terms of clauses 13 and 14.1, the provisions of the Taxation Act and the provisions of sections 11 and 15 of the Petroleum Act, no other tax, duty, fee or levy shall be imposed on the Company or its Affiliates in respect of income derived from Petroleum Operations in terms of this Agreement or in respect of any property held, money received, or thing done for any purpose authorized or contemplated in terms of this Agreement other than
|
(a)
|
customs duties prescribed from time to time in or under the Customs and Excise Act, 1998 (Act 20 of 1998) to the extent applicable;
|
(b)
|
value added tax prescribed from time to time in or under the Value-Added Tax Act, 2000 (Act 10 of 2000) to the extent applicable;
|
(c)
|
taxes, duties, fees or levies for specific services rendered on request or to the public or commercial enterprises generally;
|
(d)
|
rates, taxes or levies, not in excess of those generally applicable in Namibia, payable to any municipality or other local government in terms of or under the relevant legislation; and
|
(e)
|
stamp duties, transfer fees and licence fees, not in excess of those generally applicable in Namibia, payable to the Government or any body established by or under any law.
|
15.1.
|
The Parties hereby agree that Namibian Crude Oil Produced and Saved from the Licence Area shall be sold or otherwise disposed of at competitive international market prices.
|
15.2.
|
The market value of Namibian Crude Oil sold or otherwise disposed of in any Quarter shall, for the purposes of this Agreement and section 7(5) of the Taxation Act, be determined as follows:‑
|
(a)
|
No later than 15 days after the end of each Quarter in which Crude Oil has been Produced and Saved from any Production Area, an average price (expressed in United States Dollars per Barrel, adjusted to the Company’s actual loading points for export from Namibia) for each separate volume of Crude Oil of the same gravity, sulphur and metal content, pour point, product yield and other relevant characteristics (“quality”) shall be determined in respect of production during that Quarter. It is understood that production from different Production Areas may be of differing quality and that separate average prices may accordingly be appropriate for any Quarter in respect of production from each Production Area, in which event the overall price applicable to production from the Licence Area shall be determined by taking the arithmetic weighted average (weighted by volume) of all such prices separately determined.
|
(b)
|
The prices aforesaid shall be determined on the basis of international fair market value as follows‑
|
(i)
|
In the event of 50 per cent or more of the total volume of sales made by the Company during the Quarter of Namibian Crude Oil of a given quality Produced and Saved being by third party arms length sales transacted in foreign exchange (hereinafter referred to as third party sales), the fair market valuation for all Crude Oil of that quality will be taken to be the simple arithmetic average price, calculated by dividing the total receipts from all such third party sales by the total number of Barrels of Crude Oil sold in such sales, actually realised in such third party sales.
|
(ii)
|
Subject to paragraph (c) of this clause, in the event of less than 50 per cent of the total volume of sales made by the Company during the Quarter of Namibian Crude Oil of a given quality Produced and Saved being by third party sales, the fair market valuation for all Crude Oil of that quality will be determined by the arithmetic weighted average of‑
|
(A)
|
the simple arithmetic average price actually realised in such third party sales during the Quarter of such Crude Oil Produced and Saved, if any, calculated by dividing the total receipts from all such sales by the total number of Barrels of Crude Oil in such sales; and
|
(B)
|
the simple arithmetic average price, adjusted for differences in quality, quantity, transportation costs, delivery time, payment and other contract terms, at which a selection, determined in accordance with the terms of clause 15,3 by mutual agreement between the Parties, of major competitive crude oils of generally similar quality to that of Namibian Crude Oil Produced and Saved were sold in international markets during the same period. The arithmetic weighted average aforesaid will be determined by the percentage volume of sales of Namibian Crude Oil by the Company referred to in subparagraph (a) which are third party sales during the Quarter in question and such sales referred to in subparagraph (b) which are not third party sales during the Quarter in question.
|
(iii)
|
All prices aforesaid shall be adjusted to the Company’s actual loading point for export from Namibia.
|
(iv)
|
For purposes of this clause 15 third party sales of Namibian Crude Oil made by the Company shall exclude
|
(A)
|
sales, whether direct or indirect through brokers or otherwise, of any seller to any Affiliate of such seller;
|
(B)
|
crude oil exchanges, barter deals or restricted or distress transactions and generally any crude oil transaction which is motivated in whole or in part by considerations other than the usual economic incentives for commercial arms length crude oil sales; and
|
(C)
|
government to government sales.
|
(c)
|
In the event of‑
|
(i)
|
less than 50 per cent of the total volume of sales by the Company during the Quarter of Namibian Crude Oil of a given quality Produced and Saved being third party sales, the Minister may elect to accept determination of the fair market valuation of all Crude Oil of that quality based on third party arms length sales during that Quarter calculated in accordance with the terms of paragraph (b)(i) of clause 15.2;
|
(ii)
|
the percentage volume of sales being less than 50 per cent as aforesaid, the Company shall promptly notify the Minister and, provided the Minister does not notify the Company of his election within seven days of receipt of notification from the Company, the fair market valuation of the aforesaid Crude Oil shall be determined in terms of paragraph (b)(11) of clause 15.2.
|
15.3.
|
The selection of crude oils referred to in paragraph (b)(ii)(b) of clause 15.2 will be determined by mutual agreement between the Company and the Minister in advance for each Calendar Year and, in making the selection, preference will be given to those crude oils of similar quality to Namibian Crude Oil which are produced in Africa, South America or the Middle East and are regularly sold in the same markets as Namibian Crude Oil is normally sold.
|
15.4.
|
The Company shall‑
|
(a)
|
be responsible for establishing the relevant average prices for Namibian Crude Oil in accordance with this clause 15 and such prices shall be subject to agreement by the Minister before they shall be deemed to have been finally determined;
|
(b)
|
provide the Minister with all relevant information in order that he can satisfy himself that the average price determined by the Company is fair. If the Parties fail to agree on the average price for any Quarter within 30 days following the end of such Quarter the calculation of the relevant average price shall be referred to a sole expert appointed in terms of clause 29.6 for determination in accordance with this clause 15 whose determination shall be final and binding, and until such determination the last applied price shall be used.
|
15.5.
|
During the first Calendar Year in which Crude Oil or Crude Oil as well as Natural Gas are Produced and Saved from the Licence Area and delivered under a Development Plan, the Parties shall meet in order to establish a provisional selection of the major competitive crude oils and an appropriate mechanism for the purposes of giving effect
|
15.6.
|
In the event of any dispute between the Company and the Minister concerning the selection of the crude oils or generally about the manner in which the prices are determined according to the terms of this clause 15 any matter in dispute shall finally be resolved by a sole expert appointed in terms of clause 29.6.
|
16.1.
|
Notwithstanding the provisions of clause 8 of this Agreement, the following provisions shall apply to any Discovery of Natural Gas within the Licence Area.
|
16.2.
|
(a)
If in the course of its Exploration Operations the Company makes a Discovery of Non-Associated Natural Gas, it shall promptly inform the Minister by notice in writing of the Discovery. The Minister and the Company shall meet as soon as possible thereafter to discuss the commercial potential of such Discovery, including but not limited to, the terms and conditions on which such Gas might be developed, produced, processed and sold.
|
(a)
|
If as a result of the discussions and evaluation of test results the Company determines that the Discovery is of potential commercial interest, then the Company shall promptly undertake a market feasibility study, which shall be based on relevant economic criteria, including but not limited to, potential gas markets, gas prices, long-term gas contracts, capital costs, operating costs as well as any other relevant criteria. In connection with such study the Company shall use its best efforts to locate all potential commercial markets for such Gas. Upon completion of the study the Company shall inform the Commissioner of the results thereof and furnish him with a copy of the study within 30 days of the said completion,
|
(b)
|
Subject to the other provisions of this clause 16, the Minister hereby agrees to allow the Company to retain a Discovery Block of potential commercial interest for the duration of the Exploration Licence and any renewals thereof.
|
(c)
|
At any time after completion of the market feasibility study the Company may determine that an appraisal programme for the Discovery is warranted. In such case the Company shall propose for approval an appraisal programme to the Commissioner within a reasonable period of time thereafter, which shall not exceed three months, unless the Commissioner on good cause shown by the Company, allows a further period. If the Company and the Commissioner cannot agree on the appraisal programme, clause 5.9 shall apply mutatis mutandis. Within three months of receiving approval from the Commissioner the Company shall proceed to carry out such appraisal programme in accordance with Good Oilfield Practices.
|
(d)
|
If based on the market feasibility study the Company determines that an appraisal programme is not warranted the Company shall promptly inform the Commissioner of such determination. Such notice to the Commissioner shall be regarded as an application to the Minister, pursuant to section 39(3) of the Petroleum Act, for an exemption from the provisions of section 39(2) of the Act. If the Commissioner disagrees with such determination the Commissioner may cause an independent evaluation to be carried out. Such evaluation shall determine whether an appraisal programme is warranted. If the evaluation determines that appraisal of the Discovery is warranted then the Commissioner shall promptly notify the Company of such determination. Such notification shall be regarded as a decision by the Minister not to grant the Company exemption under section 39(3) of the Petroleum Act. The Company shall have 90 days from the date of receipt of such notification to decide whether to proceed with an appraisal programme in accordance with the provisions of clause 16.2(d). If the Company decides not to proceed with such appraisal programme the provisions of clause 8.11 shall apply mutatis mutandis. If the Commissioner does not decide within 90 days of the notification by the Company to cause an independent evaluation to be carried out, the Minister hereby agrees pursuant to section 39(3) of the Petroleum Act to grant the Company an exemption, subject to the terms of clause 16.3, from the provisions of section 39(2) of the said Act.
|
16.3.
|
The Company shall reassess the commerciality of the Discovery twelve months after the Discovery and thereafter every two years, based on the same economic criteria as set forth in clause 16.2(b). The Company shall within 30 days after the completion of each reassessment inform the Minister whether it determines the Discovery still to be of potential commercial interest. A copy of any reassessment study shall be given to the Commissioner. If as a result of the Company’s reassessment under clause 16.3 the Company determines that an appraisal programme for the Discovery is warranted the Company shall propose an appraisal programme in accordance with the provisions of clause 16.2(d).
|
16.4.
|
If as a result of any reassessment in accordance with clause 16.3, the Company determines that an appraisal programme is not warranted the Company shall promptly inform the Commissioner of such determination. If the Commissioner does not agree with such determination, the Commissioner may cause an independent evaluation to be carried out. The provisions of clause 16.2(e) regarding such evaluation and appraisal shall apply mutatis mutandis.
|
16.5.
|
If as a result of the Company’s market feasibility study under clause 16.2(b), reassessment under clause 16.3 or appraisal programme conducted pursuant to clause 16.2(d), the Company determines that the Discovery is not of potential commercial interest the provisions of clause 8.11 shall apply mutatis mutandis.
|
16.6.
|
If having carried out an appraisal programme pursuant to clause 16.2(d), the Company determines that the Discovery is not of present commercial interest but may become of commercial interest then, if the Commissioner agrees with such determination, the Minister hereby agrees to allow the Company to retain the Discovery Block for the duration of the Company’s Exploration Licence and any renewal thereof. If the
|
16.7.
|
For purposes of clause 16.2(a) the Company and the Minister shall undertake to negotiate in good faith in order to reach an agreement on a method of valuing such gas for purposes of royalty payable in terms of section 62 of the Petroleum Act and of tax payable in terms of the Taxation Act.
|
16.8.
|
The Company shall have the right to use Natural Gas for Petroleum Operations, including, but not limited to, pressure maintenance in the oilfields in the Licence Area.
|
16.9.
|
Subject to the terms of clauses 16.8, 16.10 and 16.11, the Minister shall be entitled to take at the downstream flange of the separator on the production platform or, if no such separator exists, at a point of delivery mutually agreed upon at the collecting and inlet system, and utilise without any payment to the Company any Associated Natural Gas which is in excess of the quantity of Natural Gas required for Petroleum Operations. The cost of taking and utilizing such Associated Natural Gas by the Minister shall be borne solely by the Government.
|
16.10.
|
Subject to clause 16A1, and to the Company’s requirements regarding such short term flaring as may be necessary for testing or other operational reasons, Associated Natural Gas produced from the Licence Area shall be reinjected in accordance with Good Oiifield Practices, Such Associated Natural Gas which cannot for technical reasons be re-injected may be flared only with approval in writing of the Minister previously obtained in every particular case, which approval shall not be unreasonably withheld,
|
16.11.
|
If there are reasonable grounds for believing that Natural Gas associated with Crude Oil is in such quantities as to enable its commercial exploitation without detriment to the efficient and effective recovery of Crude Oil from the Petroleum Reservoir, the Company shall promptly inform the Minister by written notice of the existence of such grounds and shall undertake a market feasibility study to determine the commercial viability of such exploitation. If such study reveals that exploitation may be commercially viable the Minister and the Company shall meet as soon as possible after completion of such study to decide whether in view of the available data the development, production, processing and sale of such Gas by the Company is possible and, if so, on what terms and conditions such Gas may be processed and sold. For such purposes the provisions of clause 16.7 shall apply mutatis mutandis.
|
16.12.
|
For the avoidance of doubt, notwithstanding the provisions of clause 7.1, the Company shall not be obliged to relinquish the Discovery Block retained by the Company pursuant to the provisions of this clause 16 for so long as it holds an Exploration Licence hereunder.
|
17.1.
|
Except to the extent insurance covering the same risk is provided by its contractors or subcontractors, the Company shall effect and, at all times during the term of this Agreement, obtain and maintain for and in relation to Petroleum Operations insurance covering the following —
|
(a)
|
loss or damage to any or all of its assets being used in connection with Petroleum Operations;
|
(b)
|
loss or damage for which the Company may be liable caused by pollution in the course of or as a result of Petroleum Operations;
|
(c)
|
loss of property or damage suffered or bodily injury suffered by any third party in the course of or as a result of Petroleum Operations for which the Company may be liable;
|
(d)
|
any claim for which the Government may be liable relating to the loss of property or damage suffered or bodily injury suffered by any third party in the course of or as a result of Petroleum Operations in so far as the Company is liable to indemnify the Government;
|
(e)
|
the cost of removing wrecks and cleaning up operations pursuant to an accident in the course of or as a result of Petroleum Operations;
|
(f)
|
the Company’s liability to its employees engaged in its Petroleum Operations;
|
(g)
|
any other risk of whatever nature as is customary to insure against in the international petroleum industry in accordance with Good Oilfield Practices.
|
17.2.
|
The Company shall require its contractors to obtain and maintain insurance against the risks referred to in paragraphs (a) to (g) of clause 17.1 relating mutatis mutandis to such contractors.
|
17.3.
|
The amount insured against, the type of insurance referred to in clause 17.1 and clause 17.2 and the terms of such insurance shall be determined in accordance with Good Oilfield Practices.
|
17.4.
|
The Company shall not within two years before the end of the term of this Agreement remove from the Licence Area or sell any Immovable Assets without the approval in writing of the Minister previously obtained in every particular case.
|
17.5.
|
Subject to any right the Company may have to occupy any Land in terms of any other petroleum agreement and the terms of this clause, the Company shall at the end of the term of this Agreement or on the date of any earlier termination thereof or the earlier relinquishment or surrender of the Licence Area or any part thereof, if by notice in writing requested to do so by the Minister, deliver to the Government any plant, pipelines, pumps, machinery of an immovable nature and any other Immovable Assets owned and used by the Company in or in connection with the Licence Area.
|
17.6.
|
The Company shall, if so requested by the Minister by notice in writing, sell to the Minister at a price determined by mutual agreement, any moveable assets of the Company used in or in connection with the Licence Area. In determining the aforesaid price due regard shall be had to
|
(a)
|
the condition of the asset concerned;
|
(b)
|
the deductions already allowed under the Taxation Act to the Company at the time of such determination.
|
17.7.
|
The terms of clause 17.6 shall not apply to any assets which are required by the Company for use by the Company in respect of Petroleum Operations in terms of any other Exploration or Production Licence.
|
17.8.
|
If the Minister decides to make the request referred to in clause 17.5 or 17.6, he shall give notice referred to in clauses 17.5 and 17.6 to the Company
|
(a)
|
in the event of this Agreement being terminated by an effluxion of time, not less than 180 days before such termination; or
|
(b)
|
in the event of this Agreement being terminated before such effluxion or any earlier relinquishment or surrender of the Licence Area or any part thereof, not later than 90 days from the date of such termination, relinquishment or surrender, as the case may be.
|
18.1.
|
The Company shall measure or weigh all Petroleum Produced and Saved from each Licence Area by a method or methods customarily used in Good Oilfield Practices and from time to time approved by the Minister.
|
18.2.
|
The Company shall not make any alteration in the method or methods of measurement or weighing used by it or any appliances used for that purpose without the consent in writing of the Minister, and the Minister may in any case require that no alteration shall be made save in the presence of a person authorized by the Minister.
|
18.3.
|
The Minister may from time to time direct that any weighing or measuring appliance be tested or examined in such manner on such occasions or at such intervals and by such means as may be specified in such direction.
|
19.1.
|
The Company shall be responsible for maintaining at an address within Namibia accounting records of all expenditure and receipts of its Petroleum Operations under
|
19.2.
|
The Minister shall have the right to appoint from time to time an auditor who shall have the right to audit for purposes of the application of the Taxation Act or any other law and this Agreement the books and accounts of the Company in respect of any year (not being a year, except in exceptional circumstances, which ended more than two years before the year in which the audit is to be carried out).
|
19.3.
|
An auditor referred to in clause 19.2 shall have the right to audit the Company’s records in accordance with the terms of the said Annexure 4.
|
19.4.
|
For purposes of any audit referred to in the said clause 19.2, the Company shall make available to the auditor all such books, records, accounts and other documents and information as may be reasonably required from the Company by him.
|
19.5.
|
Nothing in this clause contained shall be construed as prohibiting or limiting the Minister or any officer in the public service to audit or cause to be audited the books of the Company by virtue of any power conferred upon the Minister or such officer by or under any law.
|
20.1.
|
The Company shall in accordance with the provisions of the Petroleum Act at all times while this Agreement is in force, maintain accurate and current records of its Petroleum Operations in its Licence Area.
|
20.2.
|
The Company shall save and keep for the duration of its Petroleum Operations in Namibia a representative portion of each sample of cores and cuttings taken from drilling Welts to be disposed of or forwarded to the Minister in a manner directed by the Minister. All samples acquired by the Company for its own purpose shall be considered available for inspection at any reasonable time by the Minister. Any such samples which the Company has kept for a period of 12 months, without receipt of instruction to forward such samples to the Minister, may be disposed of by the Company at its discretion, after not less than 30 days notice to the Minister.
|
20.3.
|
Well logs, maps, magnetic tapes, cuts of core and cutting samples and all other geological and geophysical information obtained by the Company in the course of carrying out Petroleum Operations (hereinafter referred to as Petroleum Data) are the property of the Government, and shall be submitted to the Minister as soon as they are acquired or prepared and, except as provided in clause 20.4, may not be published, reproduced or otherwise dealt with without the consent of the Minister.
|
20.4.
|
The Company may‑
|
(a)
|
retain for use in Petroleum Operations copies of material constituting Petroleum Data;
|
(b)
|
with the approval of the Minister, retain for use in Petroleum Operations original material constituting Petroleum Data, provided that where such material is capable of reproduction, copies have been supplied to the Minister;
|
(c)
|
subject to the right conferred upon the Minister or any other person in the Petroleum Act to inspect any samples or other original materials constituting Petroleum Data, export such Petroleum Data for processing or laboratory examination or analysis, provided that representative samples equivalent in quality or, where such material is capable of reproduction, copies of equivalent quality have first been delivered to the Minister.
|
20.5.
|
The Company shall keep the Minister currently advised of all major developments taking place during the course of Petroleum Operations and shall furnish the Minister with Petroleum Data and other available information, reports, assessments, assessment studies and interpretations relating to the Petroleum Operations as the Minister may require.
|
20.6.
|
The Minister shall through his duly appointed representatives be entitled to observe the Petroleum Operations carried out by the Company and at all times to inspect all assets, records and data kept by the Company relating to such operations.
|
20.7.
|
Nothing in this clause contained shall be construed as requiring the Company to disclose any of its proprietary technology or that of its Affiliates.
|
21.1.
|
All Petroleum Data, information and reports obtained or prepared by the Company in terms of this Agreement shall, subject to clause 21.2 and so long as they relate to any part of the Licence Area, be treated as confidential and each of the Parties undertakes not to disclose such Data, information and reports or the contents thereof to any other person without the consent in writing of the other Party, provided that this clause shall not‑
|
(a)
|
prevent disclosure by the Company for the purpose of its Petroleum Operations to:‑
|
(i)
|
an Affiliate;
|
(ii)
|
any bona fide intending assignee;
|
(iii)
|
any professional adviser who needs to have access to such Petroleum Data, information and reports for the effective performance of his obligations under his contract with the Company;
|
(iv)
|
any bank or financial institution from which the Company is seeking or obtaining finance or which is advising the Company in connection with
|
(v)
|
a contractor of the Company;
|
(vi)
|
any stock exchange in order to comply with any securities law of any country;
|
(vii)
|
any court of competent jurisdiction to comply with any order or decree of such court.
|
(b)
|
prevent disclosure by the Company for the purpose of trading data with third parties in accordance with normal petroleum industry practice provided the Minister’s consent (which shall not be unreasonably withheld) has been previously applied for and obtained.
|
(c)
|
prevent the disclosure by the Minister or any officer in his Ministry to the National Petroleum Corporation of Namibia (Proprietary) Ltd. in terms of section 8 of the Petroleum Act; and to Professional advisers of the Ministry or the National Petroleum Corporation of Namibia (Proprietary) Ltd.; or
|
(d)
|
be construed as imposing on any Party any obligation in relation to any Petroleum Data, information or reports which are, without disclosure by such Party, generally known to the public.
|
21.2.
|
Any Petroleum Data, information or reports disclosed by the Company to any other person in terms of clause 21.1 shall be disclosed on terms which will ensure that such Petroleum Data, information or reports are treated as confidential by the recipient.
|
21.3.
|
Any Petroleum Data, information and reports relating to the Licence Area which, in the opinion of the Minister, might have significance in connection with an exploration programme to be conducted by a third party in another area may be disclosed by the Minister to such third party provided the Minister has previously obtained approval to do so from the Company. Such disclosure shall be subject to conditions agreed upon between the Minister and the Company.
|
21.4.
|
Any Petroleum Data, information and reports, including interpretations and assessments, assessment studies, relating to any area which ceases to be part of the Licence Area, whether as a result of relinquishment, surrender or termination of a licence shall be treated as confidential by the Company, provided however that this clause shall not:
|
(a)
|
Prevent disclosure by the Company for purpose of its Petroleum Operations to:
|
(i)
|
an Affiliate;
|
(ii)
|
any bona fide intending assignee;
|
(iii)
|
any professional adviser who needs to have access to such Petroleum Data, information and reports for the effective performance of his obligations under his contract with the Company;
|
(iv)
|
any bank or financial institution from which the Company is seeking or obtaining finance or which is advising the Company in connection with any issue of securities or the admission of any securities to listing on any stock exchange;
|
(v)
|
a contractor of the Company;
|
(vi)
|
any stock exchange in order to comply with any securities law of any country;
|
(vii)
|
any court of competent jurisdiction to comply with any order or decree of such court.
|
(b)
|
prevent disclosure by the Company for the purpose of trading data with third parties in accordance with normal petroleum industry practice provided the Minister’s consent (which shall not be unreasonably withheld) has been previously applied for and obtained.
|
(c)
|
be construed as imposing on any party any obligation in relation to any Petroleum Data, information or reports which are, without disclosure by such party, generally known to the public.
|
21.5.
|
Any Petroleum Data, information and reports, including all interpretations and assessments, assessment studies based on such Petroleum Data, information and reports relating to any area which ceases to be part of the Licence Area whether as a result of relinquishment, surrender or termination of a licence shall cease to be treated by the Minister as confidential from the date on which such area ceases to be part of the Licence Area.
|
21.6.
|
Notwithstanding the fact that Petroleum Data, information and reports relate to an area held by the Company under Licence the Minister may, using Petroleum Data, information and reports supplied by the Company:
|
(a)
|
publish, on completion of any Well by the Company in the Licence Area, the following summary information:
|
-
|
location of the Well (co-ordinates of the Well, Block number and the name of the sedimentary basin);
|
-
|
total depth of the Well in metres;
|
-
|
stratigraphic total depth of the Well identified by the Epoch (Jurassic, Cretaceous etc.);
|
-
|
Discovery of hydrocarbons, oil and/or gas or not (in case of Discovery neither the depth nor the stratigraphy of the producing formation will be given);
|
-
|
number of tests performed including type of tests;
|
-
|
maximum flow rate during testing, including size of choke;
|
-
|
hydrocarbon types tested including gas oil ratio;
|
-
|
water depth;
|
-
|
general comments on further exploration in the basin etc.
|
(b)
|
five years after the completion of any survey or any Well in the Licence Area by the Company, release to any person or persons any survey data and all Well logs and all operational, technical and geological reports relating to such survey or Well provided, however, that no information of an interpretive nature shall be released.
|
21.7.
|
Subject to the other provisions of this clause 21, the Minister may, during the currency of an Exploration or Production Licence held by the Company, request the consent of the Company to the disclosure to a third party of Petroleum Data, information and reports other than those referred to in clause 21.6 for a purpose determined by the Minister and communicated to the Company and such consent shall not be unreasonably withheld,
|
22.1.
|
In carrying out Petroleum Operations the Company shall, to the maximum extent possible, employ Namibian citizens having appropriate qualifications.
|
22.2.
|
The Company may employ a person who is not a Namibian citizen in a post only if the skills required in such post are not obtainable by recruitment of a Namibian citizen and the Company may at any time be called upon by the Minister to give satisfactory reasons for the continued employment of a non-citizen in any post.
|
22.3.
|
(a)
During each year of the Exploration Licence or any renewal thereof, the Company shall spend a sum which is not less than a sum equal to $75,000 United States Dollars for the purpose of the training and education of Namibians.
|
(a)
|
Of the said sum, 70 per cent shall be paid on the date of signature and thereafter on each anniversary of such date into the Petroleum Training and Education Fund. The principles governing the operation of the training fund shall be as set out in Annexure 6.
|
(b)
|
Of the said sum, 30 per cent shall be expended by the Company on attachments and in-house training of Namibian citizens in the field of natural science,
|
22.4.
|
The sum referred to in clause 22.3 shall be adjusted annually by dividing such sum by the Inflation Factor.
|
22.5.
|
If the Price Index ceases to be published, the Price Index shall for the purposes of this Agreement be such price index as may be determined by mutual agreement between the parties to this Agreement.
|
22.6.
|
Not later than six months after the grant of a Production Licence, the Company shall, after consultation with the Minister or his duly authorized representative, prepare and implement a programme for training and employment of Namibian citizens in each phase and level of Petroleum Operations and for the transfer of management and technical skills for the safe and efficient conduct of Petroleum Operations.
|
23.1.
|
The Company shall‑
|
(a)
|
use and purchase goods supplied, produced and manufactured in Namibia whenever such goods can be obtained at prices in Namibia which are competitive in international terms and are, in all substantive respects, of a quality comparable with the quality of goods from outside Namibia, The Company shall give preference to such supplier, producer or manufacturer, unless it is able to show good cause to the satisfaction of the Minister why such preference should not be given;
|
(b)
|
make maximum use of contractors in Namibia where services of comparable standards with those obtained elsewhere are available from such contractors at competitive prices and on competitive terms;
|
(c)
|
when it is necessary to import vehicles, machinery, plant or equipment and any such vehicles, machinery, plant or equipment are not purchased directly from a manufacturer, effect the purchase of the items through traders operating in Namibia at competitive prices;
|
(d)
|
co-operate with companies in Namibia to enable them to develop skills and technology to service the petroleum industry,
|
23.2.
|
The Company shall ensure that a term similar to this clause is contained in its contracts with contractors.
|
24.1.
|
The Company may, at the Minister’s choice, be required to sell Crude Oil in Namibia in order to satisfy Namibia’s domestic market requirements on a pro rata basis with other producers in Namibia according to the quantity of Crude Oil produced by each producer. The Minister shall give the Company at least six months notice in advance of the said requirement, and the terms of the supply in consequence of such requirement shall be on an annual basis.
|
24.2.
|
The price for Crude Oil sold in terms of clause 24.1 shall be the price for that oil determined in accordance with clause 15.
|
25.1.
|
If a Petroleum Reservoir is partly situated in the Production Area of the Company and partly in the Production Area of any other holder of a Production Licence, the Minister may, for purposes of securing the more effective recovery of Petroleum from such Petroleum Reservoir, by notice in writing addressed and delivered to the Company, direct the Company to enter into an agreement in writing with such holder within such period as may be specified in such notice in relation to the joint development and operation of such Petroleum Reservoir and to submit
|
(a)
|
such agreement forthwith to the Minister for approval; and
|
(b)
|
if it is approved, a plan for the joint development and operation of the Petroleum Reservoir in question.
|
25.2.
|
If no plan is submitted within the period specified in the notice or within such further period as the Minister may allow or, if such plan submitted is not acceptable to the Minister, the Minister may cause to be prepared in accordance with generally accepted practices in the international petroleum industry and at the expense of the Company and the other holder concerned a plan for such joint development and operation. In the preparation of such plan the Minister shall take into consideration any presentations made by the Company and such other holder.
|
25.3.
|
If the Company does not agree with the proposed plan then either the Company or the Minister may refer the matter for expert determination to an expert appointed in terms of clause 29.6 which determination shall be final except that the Company may within 60 (sixty) days of such determination notify the Minister that it elects to surrender its rights in the Discovery in lieu of participation in the joint development.
|
26.1.
|
This Agreement shall continue to be of full force and effect for such period as the Company continues to hold an Exploration Licence or a Production Licence to which
|
26.2.
|
The Minister may by notice in writing addressed and delivered to the Company terminate this Agreement if
|
(a)
|
the Company or the company which has given a performance guarantee in a form corresponding with the farm contained in Annexure 5 is liquidated by an order of a competent court;
|
(b)
|
a resolution is passed by the Company to apply to a competent court for the liquidation of the Company;
|
(c)
|
a resolution is passed by the company which has given the said performance guarantee to apply to a competent court for the liquidation of that Company;
|
(d)
|
the Company fails to comply with any final award made pursuant to arbitration proceedings conducted in terms of clause 29.
|
26.3.
|
Notwithstanding the termination of this Agreement any rights and obligations of the parties respectively expressed to arise under this Agreement on the termination thereof or any liability of any Party arising out of an earlier failure to comply with any obligation in terms of this Agreement which must be complied with by such Party shall be enforceable.
|
27.1.
|
Any failure by the Company to comply with any terms and conditions of this Agreement shall not be regarded as a breach of this Agreement in so far as the failure arises from vis major and if, as a result of vis major, the compliance by the Company with any of the terms and conditions of this Agreement is delayed beyond the period fixed or allowed for its compliance the period of the delay shall be added to the period so fixed or allowed.
|
27.2.
|
When the Company wishes to invoke the terms of clause 27.1 it shall promptly notify the Minister in writing of the occurrence of conditions of vis major and shall take all reasonable steps to remove the cause thereof and to mitigate the consequences. The Company shall promptly notify the Minister as soon as conditions of vis major no longer prevent the Company from carrying out its obligations and following such notice shall resume Petroleum Operations as soon as reasonably practicable.
|
27.3.
|
In this clause the expression “vis major means any hostility, insurrections, civil commotions, strikes, lockouts, labour disturbances, acts of God, unavoidable accidents, insurrection, civil commotion, quarantine restrictions, epidemics, storms, floods, earthquakes, lightning, fire caused by lightning, perils of navigation, war and acts of war declared or undeclared beyond the control of the Company.
|
28.1.
|
The Company may not assign to any person, firm, company or corporation which is not a party to this Agreement any of its rights, privileges, duties or obligations under this Agreement without the approval of the Minister previously obtained in every particular case which approval shall not be unreasonably withheld. The Minister shall within 90 (ninety) days from the date of the application either approve the assignment in writing or notify the Company in writing that such approval is withheld.
|
28.2.
|
Upon the approval by the Minister of an assignment pursuant to clause 28,1, the Company shall be relieved of its liabilities to the extent of the assignment of its rights and obligations under this Agreement.
|
28.3.
|
The Company shall not be debarred from assigning in writing its rights, privileges, duties or obligations under this Agreement to an Affiliate, provided that no such assignation shall in any way relieve the Company of any of its obligations under this Agreement.
|
29.1.
|
Any dispute arising between the parties relating to the construction, meaning or effect of this Agreement or the rights or liabilities of the parties in terms of this Agreement shall be resolved amicably by negotiations.
|
29.2.
|
If within 90 (ninety) days of the commencement of negotiations pursuant to clause 29.1 the Minister and the Company fail to resolve by way of negotiation a dispute referred to in clause 29.1, the Minister and the Company hereby agree to submit within 30 (thirty) days of the expiration of the first mentioned 90 (ninety) days, such dispute to arbitration for final settlement in accordance with the terms of clause 29.3.
|
29.3.
|
Any unresolved dispute referred to in clause 29.2 shall be finally settled by arbitration in accordance with the Arbitration Rules of the United Nations Commission on International Trade Law in force on the date on which this Agreement is signed. Such arbitration, unless the parties otherwise agree, shall take place in London, England. As far as practicable the Minister and the Company shall continue to implement this Agreement during the period while the arbitration is pending and during the arbitration.
|
29.4.
|
An arbitration referred to in clause 29.3 shall be undertaken by three arbitrators of whom‑
|
(a)
|
one each shall be appointed by the Minister and the Company; and
|
(b)
|
one shall be appointed by the two arbitrators appointed under paragraph (a).
|
29.5.
|
A decision of a majority of the arbitrators shall be final and binding upon the Parties and the award rendered shall be final and conclusive. The arbitrators shall state in writing the reasons on which their decision was based. Judgment on the award rendered may be entered in any court having jurisdiction or application may be made in such court for a judicial acceptance of the award and for enforcement, as the case may be.
|
29.6.
|
Any matter in dispute between the parties under clauses 5.9, 9.7, 15.6, 16 and 25.3 shall be referred for determination by a sole expert to be appointed by agreement between the parties hereto and failing such agreement by the President of the British Institute of Petroleum.
|
30.1.
|
The Company shall secure from its holding company or any Affiliate which the Minister has by notice in writing accepted an unconditional guarantee in terms whereof that company guarantees, in a form corresponding with the form contained in Annexure 5, the due performance by the Company of all its obligations under the Petroleum Act and the Taxation Act and in terms of this Agreement and the licenses to which it relates.
|
30.2.
|
The guarantee referred to in clause 30.1 shall be executed before the signature of this Agreement and shall be delivered to the Minister on such signature.
|
31.1.
|
This Agreement embodies the entire agreement and understanding between the Company and the Minister relative to the subject matter hereof, and supersedes and replaces any provisions on the same subject in any other agreement between the parties, whether written or oral, prior to the date of this Agreement.
|
31.2.
|
This Agreement may not be amended, modified, varied or supplemented, except by an instrument in writing signed by the Company and the Minister.
|
32.1.
|
The performance of any condition or obligation to be performed under this Agreement shall not be deemed to have been waived or postponed, except by an instrument in writing signed by the Party which is claimed to have granted such waiver or postponement.
|
32.2.
|
No waiver by any Party of any one or more obligations or defaults by any other party in the performance of this Agreement shall operate or be construed as a waiver of any other obligations or defaults whether of a like or a different character.
|
35.1.
|
Any document, notice or other communication required to be given or delivered to the Company by the Minister or any officer authorized thereto shall be deemed to have been so given or delivered‑
|
(a)
|
if delivered to the General Manager or Deputy General Manager referred to in clause 12.4 or to the public officer of the Company or operator referred to in paragraph (b) of clause 12.5; or
|
(b)
|
if left with some adult person apparently residing at or occupying or employed at the registered address of the Company or such operator; or
|
(c)
|
if dispatched by registered post addressed to‑
|
(i)
|
the Company or operator at the following address:
|
(ii)
|
the General Manager or Deputy General Manager referred to in clause 12.4 to the address referred to in clause 12.4; or
|
(iii)
|
the public officer at its or his last known address; or
|
(iv)
|
if transmitted by means of a facsimile transmission to the person concerned at the registered office of the Company.
|
35.2.
|
Any document, notice or other communication referred to in clause 34.1 which has been given or delivered in the manner contemplated in paragraph (c) of that clause shall, unless the contrary is proved, be deemed to have been received by the person to whom it was addressed at the time when it would, in the ordinary course of post have arrived at the place to which it was addressed.
|
35.3.
|
Any document, notice or other communication required to be given or delivered to
|
(a)
|
the Minister by the Company shall be deemed to have been so given or delivered if despatched by registered post addressed to the Minister at the following address:
|
(b)
|
the authorized officer by the Company shall be deemed to have been so given or delivered if despatched by registered post addressed to the officer at the following address:
|
(c)
|
the Minister of Finance by the Company shall be deemed to have been so given or delivered if despatched by registered post addressed to the Minister of Finance at the following address:
|
36.1.
|
Imports by Company. Company and its subcontractors shall be permitted to import all items required by Company in respect of Petroleum Operations, and all of such items and Company and its subcontractors shall be exempt from customs duties prescribed from time to time in or under the Customs and Excise Act, 1998 (Act 20 of 1998) in respect of such importation. Without limiting the foregoing, it is agreed and understood that such exemption applies to all materials, equipment, supplies, and other items including machinery, vehicles, spare parts, tires, aircraft, boats, chemicals, foodstuffs and other movable and/or consumable items for Petroleum Operations.
|
36.2.
|
Imports by Employees. Each expatriate employee of Company and its subcontractors shall be permitted to import and shall be exempt from all customs duties with respect to the importation of household goods and other personal items, including one automobile every three (3) years; provided, however, that such items are imported for the sole use of the employee and the employee’s family; and provided, further, that no such item imported by the employee shall be resold by such employee in a member country of the Southern African Customs Union except in accordance with any applicable laws.
|
36.3.
|
Disposal of Imported Items. Any item imported by Company or its subcontractors may be sold in Namibia upon payment of applicable customs duties, if any, on the price of the item at the time of such sale, or may be exported pursuant to clause 35.4. Items imported by Company or its subcontractors, which are sold or saleable only for scrap value may be sold as such, or otherwise be properly disposed of, without payment of customs duties. In the event of a sale by Company or its subcontractors under this clause 35.4, Company or its subcontractor shall be entitled to retain and repatriate in a convertible currency the proceeds therefrom as provided in this Agreement.
|
36.4.
|
Exports.
|
(a)
|
Any of the items imported into Namibia by Company, its subcontractors or their employees, which has not become the property of the Government pursuant to the provisions hereof may be exported by the importing party at any time without payment of any customs duties or other charges.
|
(b)
|
Company shall be free to export any and all Petroleum to which it is entitled pursuant to this Agreement and all Petroleum exported by Company shall be exempt from all charges in respect of exports of Petroleum.
|
37.1.
|
Registration. Funds transferred into Namibia for local expenditures, funds utilized abroad to purchase goods and services for Petroleum Operations, charges for services performed by Company or its subcontractors outside Namibia as part of Petroleum Operations and all other expenditures and investments made pursuant to
|
37.2.
|
Funds for Local Expenditures. Funds required by Company and foreign subcontractors to meet local expenditures shall be imported into Namibia in freely convertible currencies, transferred to local banks and converted to Namibia currency. If it or they so desire, Company and/or its foreign subcontractors may borrow Namibia currency from local banks in order to meet local expenditures.
|
37.3.
|
Foreign Exchange. Purchase or sale of foreign exchange shall be affected at the exchange rate most favorable to Company, as quoted by the Bank of Namibia.
|
37.4.
|
Foreign Bank Accounts. Company is hereby authorized to open, maintain, control and operate accounts in any currency in foreign banks outside Namibia, to have full and complete control of such accounts, and to retain abroad and freely dispose of any funds in such accounts. Among other reasons, withdrawals may be made for payments for goods and services acquired abroad, for payments to subcontractors engaged in Petroleum Operations, and for transferring funds to local banks in Namibia to meet local expenditures, all in connection with Company’s activities under this Agreement.
|
37.5.
|
Exchange Rights. Company is hereby granted the following exchange rights:
|
(a)
|
To provide in freely convertible foreign currencies all funds needed to conduct Petroleum Operations;
|
(b)
|
To hold such funds abroad with no obligation to transfer funds or assets to Namibia except such funds as are necessary to meet Company’s need for Namibia currency, in the case that Company does not borrow such funds from local banks;
|
(c)
|
To freely dispose of any funds held outside Namibia;
|
(d)
|
To export any and all Petroleum to which it is entitled pursuant to this Agreement;
|
(e)
|
To retain abroad and freely dispose of all proceeds received outside from the export, sale or exchange of Petroleum with no obligation to remit such export proceeds except as may be needed to meet Company’s expenses in Namibia, in the case that Company does not borrow funds from local banks for that purpose;
|
(f)
|
To remit and/or repatriate abroad and freely dispose of all (i) proceeds received within Namibia from the sale or exchange of Petroleum within Namibia, (ii) proceeds received from other operations and activities within Namibia, and (iii) any other funds accruing to Company within Namibia, including, without limiting the generality of the foregoing, all profits and or dividends; such remittance and/or repatriation to be accomplished in accordance with procedures of any exchange control Laws which may be in force, but which shall in no event prevent or delay such remittance and/or repatriation;
|
(g)
|
To pay its subcontractors and employees in foreign currencies, either inside or outside of Namibia. Expatriate employees shall be required to bring into Namibia through local banks and convert into Namibia currency only such foreign exchange as is required to meet their personal living expenses. Such employees shall be authorized to remit and/or repatriate any personal funds or proceeds received in Namibia from the sale of personal belongings; and
|
(h)
|
To maintain a special account or accounts for non-Namibian funds in a local bank or banks chosen by Company from which funds can be disbursed for the purpose of making any payments required in conducting Petroleum Operations, or making payments to, or for the benefit of, Company’s employees, whether local or expatriate
|
37.6.
|
Payments under this Agreement. Any payments made by any Party to another Party shall be made in U.S. Dollars unless the Parties mutually agree upon another currency.
|
37.7.
|
Subcontractors. Company’s subcontractors and their employees shall have the same rights as Company and its employees under this clause 37.
|
37.8.
|
Implementation. The Company acknowledges that the provisions of this clause 37 are granted in accordance with and subject to the Exchange Control Laws applicable in Namibia, and shall only be implemented by the parties in accordance with such laws, The Company shall comply with the prescribed formalities and procedures and engage the services of an authorized dealer in foreign exchange to assist it in facilitating and implementing the provisions of this clause 37.
|
/s/ Isak Katali
|
MINISHTER OF MINES AND ENERGY
|
(On behalf of the Government of Namibia)
|
Witnesses:
|
|
|
|
1.
|
/s/ Witness
|
|
|
2.
|
/s/ Witness
|
/s/ Wade Cherwayko
|
SIGNET PETROLEUM LIMITED
|
Witnesses:
|
|
|
|
1.
|
/s/ Witness
|
|
|
2.
|
/s/ Witness
|
/s/ Moses Hauwanga
|
CRICKET INVESTMENTS (PTY) LTD
|
Witnesses:
|
|
|
|
1.
|
/s/ Witness
|
|
|
2.
|
/s/ Witness
|
/s/ Robert Mwanachilenga
|
NATIONAL PETROLEUM CORPORATION OF NAMIBIA
|
Witnesses:
|
|
|
|
1.
|
/s/ Witness
|
|
|
2.
|
/s/ Witness
|
Blocks
|
Points
|
Coordinates
|
|
|
|
|
|
|
A
|
13° 30’ 00”E
|
29°00’00”S
|
|
B
|
14° 00’ 00”E
|
29°00’00”S
|
|
C
|
14° 00’ 00”E
|
29°30100”S
|
|
D
|
15° 00’ 00”E
|
29°30’00”S
|
|
E
|
15° 00’ 00”E
|
29°37’619”S
|
2914B
|
F
|
14° 00’ 00”E
|
30°35’088”S
|
I.
|
perform before the expiration of the Initial Exploration Period defined in clause 1 of the Agreement certain minimum exploration work obligations (hereinafter referred to as “the minimum initial exploration work obligation”);
|
II.
|
to incur in the performance of the minimum initial exploration work obligation, minimum exploration expenditure in an amount of in constant price terms (Insert amount which corresponds with the
|
A.
|
failed to incur the minimum initial exploration expenditure in respect of the initial exploration work obligation;
|
B.
|
actually incurred expenditure on the initial exploration work obligation which amounts to an amount (to be specified in constant 199.. price terms in constant 199.. price terms in such written demand) which is less than the minimum initial exploration expenditure;
|
C.
|
consequently, become liable to pay a shortfall of expenditure expressed in constant 199.. price terms equal to the difference between the amount
|
D.
|
failed to pay the Minister of Mines and Energy an amount equal to the shortfall referred to in paragraph C above, as adjusted by multiplying such amount by a figure obtained by dividing the Price Index, as reported for the first time in the monthly publication
|
1.
|
our liability hereunder shall be limited to paying an amount not exceeding ..$500,000 (Five Hundred Thousand) United States Dollars (insert an amount numerically greater than the minimum initial exploration expenditure, based on an estimated inflation element for the Initial Exploration Period) in respect of the initial exploration work obligation;
|
2.
|
our liability referred to in paragraph 1 shall be reduced at the end of every Quarter by the amount of the actual expenditure incurred by the Company and stated in a certificate signed by the Company and the Minister of Mines and Energy, which reduction shall take effect as from the date of receipt of such certificate by us;
|
3.
|
this guarantee shall come into effect as from the date of our receipt of a certificate signed by the Company and the Minister of Mines and Energy stating that the Agreement has been signed by all the parties thereto;
|
4.
|
this guarantee may not be ceded, assigned or transferred to any other person;
|
5.
|
this guarantee shall expire on the date of‑
|
(1)
|
the payment by us of all the amounts guaranteed hereunder; or
|
(2)
|
the receipt by us of a certificate in accordance with paragraph 2 above, whereby expenditure actually incurred in performance of the initial exploration work obligation when added to the aggregate amount of expenditure actually incurred in performance of the initial exploration work obligation, all such expenditures being adjusted to constant 199.. price terms, and stated in such certificate previously
|
(3)
|
the one hundred and twentieth day after the end of the Initial Exploration Period as defined in clause 1 of the Agreement, whichever is the earliest date, whereafter we shall be under no liability whatsoever under this guarantee;
|
6.
|
any certificate required to be provided by the Company pursuant to paragraphs 2 and 3 above must be signed by a duly authorised representative of the Company;
|
7.
|
any demand, certificate and notification must be sent to us at the above address.
|
I.
|
to perform before the expiration of the First Renewal Exploration Period defined in clause 1 of the Agreement certain minimum exploration work obligations (hereinafter referred to as “the minimum first renewal exploration work obligation”);
|
II.
|
to incur in the performance of the minimum first renewal exploration work obligation, minimum exploration expenditure in an amount of in constant 199__ price terms (Insert amount which corresponds with the amount of the minimum exploration expenditure specified in paragraph 4.1.(b)(ii) of the Agreement) (hereinafter referred to as “minimum first renewal exploration expenditure”);
|
A.
|
failed to incur the minimum first renewal exploration expenditure in respect of the first renewal exploration work obligation;
|
B.
|
actually incurred expenditure on the first renewal exploration work obligation which amounts to an amount (to be specified in constant 199... price terms in such written demand) which is less than the minimum first renewal exploration expenditure;
|
C.
|
consequently, become liable to pay a shortfall of expenditure expressed in constant 199.. price terms equal to the difference between the amount referred to in paragraph A above and the amount specified in paragraph B above; and
|
D.
|
failed to pay the Minister of Mines and Energy an amount equal to the shortfall referred to in paragraph C above, as adjusted by multiplying such amount by a figure obtained by dividing the Price Index, as reported for the first time in the monthly publication “International Financial Statistics” of the International Monetary Fund in the section “Prices, Production, Employment”, for the Calendar Month immediately preceding the day of receipt of the aforesaid written demand, by such Price Index as so reported for the Calendar Month in which the Agreement has been signed, we shall pay to the Minister of Mines and Energy the amount referred to in paragraph D above.
|
1.
|
our liability hereunder shall be limited to paying an amount not exceeding $1,000,000 (One Million). United States Dollars (insert an amount numerically greater than the minimum first renewal exploration expenditure, based on inflation during the Initial Exploration Period and an estimated inflation element for the First Renewal Exploration Period) in respect of the first renewal exploration work obligation;
|
2.
|
our liability referred to in paragraph 1 shall be reduced at the end of every Quarter by the amount of the actual expenditure incurred by the Company and stated in a certificate signed by the Company and the Minister of Mines and Energy, which reduction shall take effect as from the date of receipt of such certificate by us;
|
3.
|
this guarantee shall come into effect as from the date of our receipt of a certificate signed by the Company and the Minister of Mines and Energy stating that the Minister has granted the Company’s application for the first renewal of the licence issued under the Agreement;
|
4.
|
this guarantee may not be ceded, assigned or transferred to any other person;
|
5.
|
this guarantee shall expire on the date of‑
|
(1)
|
the payment by us of all the amounts guaranteed hereunder; or
|
(2)
|
the receipt by us of a certificate in accordance with paragraph 2 above, whereby the expenditure actually incurred in performance of the first renewal exploration work obligation and stated therein, when added to the aggregate of —
|
(a)
|
the sum by which expenditure actually incurred in performance of the initial exploration work obligation, which exceeded the minimum initial exploration expenditure and which was carried over to the First Renewal Period as contemplated in clause 4.5 of the Agreement and stated as such in a certificate signed by the Company and the Minister of Mines and Energy; and
|
(b)
|
the expenditure actually incurred in performance of the first renewal exploration work obligation and stated in such certificate previously received by us, all such expenditures being adjusted to constant 199__ price terms, shall equal or exceed the minimum first renewal exploration expenditure;
|
(3)
|
the one hundred and twentieth day after the end of the First Renewal Exploration Period as defined in clause 1 of the Agreement, whichever is the earliest date, whereafter we shall be under no liability whatsoever under this guarantee;
|
6.
|
any certificate required to be provided by the Company pursuant to paragraphs 2, 3 and 5(2)(a) above must be signed by a duly authorised representative of the Company;
|
7.
|
any demand, certificate and notification must be sent to us at the above address.
|
I.
|
to perform before the expiration of the First Renewal Exploration Period defined in clause 1 of the Agreement certain minimum exploration work obligations (hereinafter referred to as “the minimum first renewal exploration work obligation”);
|
II.
|
to incur in the performance of the minimum first renewal exploration work obligation, minimum exploration expenditure in an amount of _________ in constant 199__ price terms (Insert amount which corresponds with the amount of the minimum exploration expenditure specified in paragraph 4.1.(b)(ii) of the Agreement) (hereinafter referred to as “minimum first renewal exploration expenditure”);
|
A.
|
failed to incur the minimum first renewal exploration expenditure in respect of the first renewal exploration work obligation;
|
B.
|
actually incurred expenditure on the first renewal exploration work obligation which amounts to an amount (to be specified in constant 199.. price terms in such written demand) which is less than the minimum first renewal exploration expenditure;
|
C.
|
consequently, become liable to pay a shortfall of expenditure expressed in constant 199.. price terms equal to the difference between the amount referred to in paragraph A above and the amount specified in paragraph B above; and
|
D.
|
failed to pay the Minister of Mines and Energy an amount equal to the shortfall referred to in paragraph C above, as adjusted by multiplying such amount by a figure obtained by dividing the Price Index, as reported for the first time in the monthly publication “International Financial Statistics” of the International Monetary Fund in the section “Prices, Production, Employment”, for the Calendar Month immediately preceding the day of receipt of the aforesaid written demand, by such Price Index as so reported for the Calendar Month in which the Agreement has been signed, we shall pay to the Minister of Mines and Energy the amount referred to in paragraph D above,
|
1.
|
our liability hereunder shall be limited to paying an amount not exceeding $1,000,000 (One Million). United States Dollars (insert an amount numerically greater than the minimum first renewal exploration expenditure, based on inflation during the Initial Exploration Period and an estimated inflation element for the First Renewal Exploration Period) in respect of the first renewal exploration work obligation;
|
2.
|
our liability referred to in paragraph 1 shall be reduced at the end of every Quarter by the amount of the actual expenditure incurred by the Company and stated in a certificate signed by the Company and the Minister of Mines and Energy, which reduction shall take effect as from the date of receipt of such certificate by us;
|
3.
|
This guarantee shall come into effect as from the date of our receipt of a certificate signed by the Company and the Minister of Mines and Energy stating that the Minister has granted the Company’s application for the first renewal of the licence issued under the Agreement;
|
4.
|
this guarantee may not be ceded, assigned or transferred to any other person;
|
5.
|
this guarantee shall expire on the date of‑
|
(1)
|
the payment by us of all the amounts guaranteed hereunder; or
|
(2)
|
the receipt by us of a certificate in accordance with paragraph 2 above, whereby the expenditure actually incurred in performance of the first renewal exploration work obligation and stated therein, when added to the aggregate of —
|
(a)
|
the sum by which expenditure actually incurred in performance of the initial exploration work obligation, which exceeded the minimum initial exploration expenditure and which was carried over to the First Renewal Period as contemplated in clause 4.5 of the Agreement and stated as such in a certificate signed by the Company and the Minister of Mines and Energy; and
|
(b)
|
the expenditure actually incurred in performance of the first renewal exploration work obligation and stated in such certificate previously received by us, all such expenditures being adjusted to constant 199… price terms, shall equal or exceed the minimum first renewal exploration expenditure;
|
(3)
|
the one hundred and twentieth day after the end of the First Renewal Exploration Period as defined in clause 1 of the Agreement, whichever is the earliest date, whereafter we shall be under no liability whatsoever under this guarantee;
|
6.
|
any certificate required to be provided by the Company pursuant to paragraphs 2, 3 and 5(2)(a) above must be signed by a duly authorised representative of the Company;
|
7.
|
any demand, certificate and notification must be sent to us at the above address.
|
3.1
|
Each of the entities constituting the Company shall be responsible for maintaining their own accounting records in order to comply fully with all legal requirements and to support all fiscal returns or any other accounting reports required by any governmental authority in relation to the Petroleum Operations.
|
3.2
|
The operator for and on behalf of all entities constituting the Company shall maintain the accounts of the Petroleum Operations under the Agreement in such a manner so as to permit each such entity to fulfill the obligations under this Agreement.
|
4.1
|
Within 90 days of the date on which the Agreement has been signed the Minister shall submit, to discuss and agree with the Company, a proposed outline of charts of accounts, operating records and reports, which outline shall reflect each of the categories and sub-categories of expenditures specified in paragraph 8 and shall be in accordance with generally accepted and recognised accounting systems and consistent with normal practice for joint venture operations of the international petroleum industry.
|
4.2
|
Within 180 days after the date on which the Agreement has been signed the Company shall provide the Minister with a detailed description of the accounting systems and procedures which it will develop and maintain for use under the
|
4.3
|
Notwithstanding the generality of the foregoing, the Company shall submit the following statements to the Minister -
|
(a)
|
a production statement referred to in paragraph 11 of this Annexure;
|
(b)
|
a value of production and pricing statement referred to in paragraph 12 of this Annexure.
|
(c)
|
a statement of expenditure and receipts referred to in paragraph 13 of this Annexure;
|
(d)
|
an additional profits tax statement referred to in paragraph 14 of this Annexure;
|
(e)
|
an end-of-year statement referred to in paragraph 15 of this Annexure;
|
(f)
|
a budget statement referred to in paragraph 16 of this Annexure;
|
(g)
|
a local procurement statement referred to in paragraph 17 of this Annexure,
|
(h)
|
a decommissioning statement referred to in paragraph 18 of this Annexure
|
4.4
|
All reports and statements shall be prepared in accordance with the Agreement, the laws of Namibia and, where there are no relevant provisions in either of these, in accordance with normal practice of the international petroleum industry.
|
5.1
|
Accounts shall be maintained in Namibian Dollars. Metric units and Barrels shall be employed for measurements required under the Agreement and this Annexure. The language employed shall be English. When necessary for clarification the Company shall also maintain accounts and records in other languages, units of measurement and currencies.
|
5.2
|
It is the intention of the parties that neither the Government nor the Company should experience an exchange gain or loss at the expense of or to the benefit of the other. However, should there be any gain or loss from exchange of currency, it will be credited or charged to the accounts.
|
5.3
|
Amounts received and expenditures made in Namibian Dollars or in United States Dollars shall be converted from Namibian Dollars into United States Dollars or from United States Dollars into Namibian Dollars on the basis of the monthly average of the mean of the daily official buying and selling exchange
|
5.4
|
Amounts received and expenditures made in currencies other than United States Dollars and Namibian Dollars shall be converted into United States Dollars or Namibian Dollars on the basis of the monthly average of the mean of the daily buying and selling exchange rates between the currencies in question as published by the Bank of Namibia or, failing such publication, as published in the Financial Times (London edition) for the Calendar Month in which the relevant transaction occurred.
|
5.5
|
The average monthly exchange rates used in accordance with paragraphs 5.3 and
|
5.6
|
shall be identified in the relevant statements required under paragraph 4.3.
|
6.1
|
Unless otherwise specified all sums due under the Agreement shall be paid within 30 days following the end of the month in which the obligation to make such payment occurs and shall be paid through a bank designated by each Party.
|
6.2
|
Ali sums due by one Party to the other under the Agreement during any Quarter shall for each day during which such sums are overdue during such Quarter, bear interest compounded daily at an annual rate equal to 15%.
|
7.1
|
The Government shall have the right
|
(a)
|
to carry out an audit in accordance with clause 19.2 of the Agreement;
|
(b)
|
to appoint an auditor to undertake or assist with the audit.
|
7.2
|
The Company shall answer any notice of exception under paragraph 7.1 within six months of the receipt of such notice. Where the Company has after the said six month period failed to answer a notice of exception made by the Minister, the Minister’s exception shall prevail, until such time as the Minister’s exception is resolved.
|
7.3
|
Without prejudice to the finality of matters as described in Clause 19 and this paragraph all documents referred to in paragraph 7.1 shall be maintained and made available for inspection by the Minister for seven years following their date of issue.
|
8.1
|
All expenditures relating to Petroleum Operations and qualifying in terms of the Taxation Act, Petroleum Act and paragraph 9 to be taken into account in the calculation of petroleum income tax and additional profits tax payable under the Taxation Act shall be classified, defined and allocated, as follows‑
|
(1)
|
exploration expenditure, being expenditure actually incurred, whether directly or indirectly, in or in connection with the carrying out of Exploration Operations in or in connection with such Licence Area, including expenditure actually incurred in respect of‑
|
(a)
|
the acquisition of machinery, implements, utensils and other articles employed for purposes of such operations, including pipes, well-head equipment, subsurface equipment and onshore and offshore drilling;
|
(b)
|
labour, fuel, haulage, supplies, materials and repairs in connection with a survey or study, excluding drilling for appraisal purposes, referred to in paragraphs (a) and (b) of the definition of “Exploration Operations” in section 1 of the Petroleum Act;
|
(c)
|
contributions to a fund or scheme, approved by the Permanent Secretary: Finance, in respect of any person employed in or in connection with Exploration Operations;
|
(d)
|
the advancement of training and education of Namibian citizens at institutions approved by the Permanent Secretary: Finance and the provision of educational and scientific materials and equipment by virtue of any term and condition of an Exploration Licence issued in respect of such Licence Area;
|
(e)
|
charges, fees or rent for, or in respect, of Land or buildings occupied for purposes of carrying out Exploration Operations;
|
(f)
|
subject to the provisions of section 14(2) of the Taxation Act, the general administration and management directly connected with Exploration Operations;
|
(g)
|
the restoration of such Licence Area, or any part thereof, after cessation of Exploration Operations in such area to the extent to which such expenditure has been incurred by virtue of any term and condition of an Exploration Licence issued in respect of such Licence Area relating to safety or the prevention of pollution;
|
(h)
|
customs duty in respect of the importation for use in or in connection with Exploration Operations in such Licence Area of plant, machinery, equipment, spare parts, materials, supplies or consumable items used in or in connection with such Exploration Operations;
|
(2)
|
development expenditure, being expenditure actually incurred, whether directly or indirectly, in or in connection with the carrying out of Development Operations in or in connection with a Licence Area, including expenditure actually incurred in respect of
|
(a)
|
the acquisition of‑
|
(i)
|
machinery, implements, utensils and other articles used for purposes of such operations, including pipes, units for purposes of production, treatment and processing, wellhead equipment, subsurface equipment, enhanced recovery systems, onshore and offshore drilling and production platforms and petroleum storage facilities;
|
(ii)
|
furniture, tools and equipment used in offices and accommodation referred to in paragraph (e)(ii) of the definition of “Development Operations” in section 1 of the Taxation Act and in warehouses, export terminals, harbours, piers, marine vessels, vehicles, motorised rolling equipment, aircraft, fire and security stations, water and sewage plants and power plants;
|
(b)
|
labour, fuel, haulage, supplies, materials and repairs in connection with the drilling, laying, installation and construction referred to in paragraphs (a), (b), (c), (d) and (e)(i) of the definition of “Development Operations” in section 1 of the Taxation Act;
|
(c)
|
contributions to a fund or scheme, approved by the Permanent Secretary: Finance, in respect of any person employed in or in connection with Development Operations;
|
(d)
|
the advancement of training and education of Namibian citizens at institutions approved by the Permanent Secretary: Finance and the provision of educational and scientific materials and
|
(e)
|
charges, fees or rent for, or in respect of, Land or buildings occupied for purposes of carrying out Development Operations;
|
(f)
|
subject to the provisions of section 14(2) of the Taxation Act, the general administration and management directly connected with Development Operations; (g) the restoration of such Licence Area, or any part thereof, after cessation of Development Operations in such Licence Area to the extent to which such expenditure has been incurred by virtue of any term and condition of the licence issued in respect of such Licence Area relating to safety or the prevention of pollution;
|
(g)
|
customs duty in respect of the importation for use in or in connection with Development Operations in such Licence Area of plant, machinery, equipment, spare parts, materials, supplies or consumable items used in or in connection with such Development Operations;
|
(3)
|
production expenditure, being expenditure of an operational nature incurred in Production Operations and which, subject to section 13 of the Taxation Act and paragraph 9 of this Annexure, is allowed as a general deduction in the determination of taxable income in terms of section 8 of the Taxation Act;
|
(4)
|
general and administrative expenditure which‑
|
(a)
|
being the expenditure incurred on general administration and management primarily and principally related to Petroleum Operations in or in connection with the Licence Area, comprises and is limited to —
|
(i)
|
office, field office and general administrative expenditure in Namibia, including supervisory, accounting and employee relations services (excluding commissions paid to intermediaries by the Company);
|
(ii)
|
an annual overhead charge for services rendered outside Namibia and not otherwise charged under this accounting procedure, for managing Petroleum Operations and for staff advice and assistance including financial, legal, accounting and employee relations services, provided that ‑
|
(A)
|
for the period from the date on which the Agreement was signed until the date on which the first Production Licence under the Agreement is granted by the Minister, this annual charge shall be
|
(B)
|
for the period from the date on which the Production Licence has been granted, the charge shall be at an amount or rate to be agreed on between the parties and stated in the Development Plan approved with the grant of the Production Licence;
|
(C)
|
such annual overhead charge shall be separately shown in all relevant reports to the Minister;
|
(b)
|
shall be allocated to and form part of exploration expenditure, development expenditure and production expenditure and shall be separately shown under each of these expenditure categories in all relevant reports and statements to the Minister;
|
(c)
|
shall be allocated to exploration expenditure, development expenditure and production expenditure incurred in each year in proportion to the amount of exploration expenditure, development expenditure and production expenditure incurred in such year, or in such other equitable and consistent manner otherwise agreed upon between the Company and the Minister.
|
9.1
|
Expenditure deductible without further approval of the Government Subject to the terms of the Agreement, the Company shall bear and pay the following expenditure in respect of its Petroleum Operations. These expenditures shall be classified under the headings referred to in paragraph 8. It is hereby agreed that, subject to the provisions of sections 8, 9 and 10 of the Taxation Act and paragraph 8, such expenditures are to be allowable deductions under the Taxation Act.
|
(1)
|
Surface rights
|
(2)
|
Labour and related expenditure
|
(a)
|
Gross salaries and wages, including bonuses, of the Company’s employees directly and necessarily engaged in the Petroleum Operations, irrespective of the location of such employees, it being understood that in the case of those employees, only a portion of whose time is wholly dedicated to Petroleum
|
(b)
|
Cost to the Company of established plans for employees’ group life insurance, hospitalization, company pension, retirement and other benefits of a like nature customarily granted to the Company’s employees and the Company’s expenditure regarding holiday, vacation, sickness and disability payments applicable to the salaries and wages chargeable under subparagraph (a) above shall be allowed at actual cost, provided however that such total expenditure shall not exceed thirty-five per cent of the Company’s total labour expenditure under subparagraph (a) above.
|
(c)
|
Expenditure or contributions made pursuant to assessments or obligations imposed under the laws of Namibia which are applicable to the Company’s expenditure on salaries and wages chargeable under subparagraph (a) above.
|
(d)
|
Reasonable travel and personal expenditure of employees of the Company, including those made for travel and relocation of the expatriate employees assigned to Namibia all of which shall be in accordance with the Company’s normal practice.
|
(3)
|
Transportation
|
(4)
|
Charges for services
|
(a)
|
Third party contracts
|
(b)
|
Affiliates of the Company In the case of services rendered to the Petroleum Operations by an Affiliate of the Company the charges shall be based on actual expenditure without profits and shall be competitive. The charges shall be no higher than the most favourable prices charged by the Affiliate to third parties for comparable services under similar terms and conditions elsewhere. The Company shall, if requested by the Minister, specify the amount of the charges which constitutes an allocated
|
(c)
|
In the event that the prices and charges referred to in subparagraph (4) (a) and (b) above are shown to be uncompetitive then the Permanent Secretary: Finance shall have the right to disallow as a deduction under the Taxation Act such portion as he deems fit.
|
(5)
|
Exclusively owned property For services rendered to the Petroleum Operations through the use of property exclusively owned by the Company, the accounts shall be charged at rates not exceeding those prevailing in the region which reflect the cost of ownership and operation of such property or at rates to be agreed.
|
(6)
|
Material and equipment
|
(a)
|
General
|
(b)
|
Warranty of material The Company does not warrant material beyond the supplier’s or manufacturer’s guarantee and, in the case of defective material or equipment, any adjustment received by the Company from the suppliers or manufacturers or their agents will be credited to the accounts under the Agreement.
|
(c)
|
Value of material charged to the accounts under the Agreement
|
(i)
|
Except as otherwise provided in subparagraph (ii) below, material purchased by the Company for use in the Petroleum Operations shall be valued to include invoice price less trade and cash discounts, if any, purchase and procurement fees plus freight and forwarding charges between point of supply and point of shipment, freight to port of destination, insurance, taxes, custom duties, consular fees, other items chargeable against imported material and, where applicable, handling and transportation costs from point of importation to warehouse or operating site, and its costs shall not exceed
|
(ii)
|
Material purchased from or sold to Affiliated companies of the Company or transferred to or from activities of the Company other than Petroleum Operations under the Agreement‑
|
(A)
|
in the case of new material (hereinafter referred to as condition A), shall be valued at the current international price which shall not exceed the price prevailing in normal arms length transactions on the open market;
|
(B)
|
in the case of used material which is in sound and serviceable condition and is suitable for re-use without reconditioning (hereinafter referred to as condition B), shall be priced at not more than seventy-five per cent of the current price of the abovemenfioned new materials;
|
(C)
|
in the case of used material which cannot be classified as condition B, but which, after reconditioning, will be further serviceable for original function as good second hand condition B material or is serviceable for original function, but substantially not suitable for reconditioning (hereinafter referred to as condition C) shall be priced at not more than fifty per cent of the current price of the new material referred to above as condition A.
|
(7)
|
Insurance and losses
|
(8)
|
Training expenditure
|
(9)
|
General and administrative expenditure
|
9.2
|
Expenditure riot deductible under the Agreement
|
(a)
|
All expenditure incurred before the date on which the Agreement was signed.
|
(b)
|
Interest and any other finance charges or fees incurred on loans raised by the Company, except as is provided under section 8(a)(iv) of the Taxation Act.
|
(c)
|
Petroleum marketing or transportation expenditure of Petroleum beyond the actual loading point of the Company for export from Namibia in the case of Crude Oil and in the case of Natural Gas the geographical point of sale.
|
(d)
|
The cost of obtaining and maintaining the bank guarantee and the performance guarantee required under the Agreement (and any other amounts spent on indemnities with regard to non-fulfilment of contractual obligations).
|
(e)
|
Donations and charitable contributions.
|
(f)
|
Expenditure incurred in relation to arbitration and the sole expert in respect of any dispute under the Agreement.
|
(g)
|
Fines and penalties imposed by courts of law in Namibia.
|
(h)
|
The premium of 500 per cent and the additional amounts of 200 per cent and 600 per cent payable to the Government under clauses 8.14(c) and 10.4 of the Agreement.
|
(i)
|
The interest payable to the Government in terms of clause 11.14 of the Agreement.
|
(j)
|
Expenditure incurred as a result of willful misconduct or negligence of the Company.
|
(k)
|
Any expenditure which by reference to general oil industry practices can be shown to be excessive.
|
9.3
|
Other expenditure
|
9.4
|
Miscellaneous income and credits under the Agreement
|
(a)
|
The net proceeds of any insurance or claim in connection with the Petroleum Operations or any assets charged to the accounts under the Agreement when such operations or assets were insured and the premiums charged to the accounts under the Agreement.
|
(b)
|
Revenue received from third parties or Affiliated companies for the use of property or assets charged to the accounts under the Agreement,
|
(c)
|
Any adjustment received by the Company from the suppliers or manufacturers or their agents in connection with defective material the expenditure of which was previously charged by the Company to the accounts under the Agreement.
|
(d)
|
Rentals, refunds or other credits received by the Company which apply to any charge which has been made to the accounts under the Agreement, but excluding any award granted to the Company under arbitration or sole expert proceedings referred to in paragraph 9.2(f) above.
|
(e)
|
The prices originally charged to the accounts under the Agreement for materials subsequently exported from Namibia without being used in the Petroleum Operations.
|
(f)
|
The proceeds from the sale or exchange by the Company of plant or facilities from the Licence Area or plant or facilities the acquisition expenditure of which have been charged to the accounts under the Agreement.
|
(g)
|
The proceeds from the sale or exchange by the Company of any Petroleum rights being an interest in its Licence Area.
|
(h)
|
The proceeds from the sale of any Petroleum information which relates to the Licence Area provided that the expenditure incurred in respect of the acquisition of such information has been charged to the accounts under the Agreement,
|
(2)
|
The proceeds derived from the sale or licence of any intellectual property the development costs of which were incurred under the Agreement.
|
9.5
|
Duplication of charges and credits
|
10.1
|
The Company shall keep and maintain detailed records of assets in use for or in connection with Petroleum Operations in accordance with normal accounting practices in exploration and production activities of the international petroleum industry.
|
10.2
|
The Company shall furnish particulars to the Minister by notice in writing addressed and delivered to the Minister at six monthly intervals of all assets acquired by the Company to be used for or in connection with Petroleum Operations during the period immediately preceding the delivery of such notice.
|
10.3
|
The Company shall‑
|
(a)
|
not less than once every twelve months with respect to movable assets; and
|
(b)
|
not less than once every four years with respect to immovable Assets, take an inventory of the assets used for or in connection with Petroleum Operations in terms of the Agreement and address and deliver such inventory to the Minister together with a written statement of the principles upon which valuation of the assets mentioned in such inventory has been based.
|
10.4
|
The Company shall give the Minister at least 30 days notice in writing addressed and delivered to the Minister of its intention to take the inventory referred to in paragraph 10,3 and the Minister shall have the right to be represented when such inventory is taken.
|
10.5
|
When an assignation of rights under the Agreement takes place a special inventory shall be taken by the Company at the request of the assignee provided that the cost of such inventory is borne by the assignee and paid to the Company.
|
10.6
|
in order to give effect to clauses 17.5 and 17.6 of the Agreement the Company shall provide the Government with a comprehensive list of all relevant assets when requested by the Minister to do so.
|
11.1
|
The Company shall, not later than seven days after the end of the first Calendar Month during which Petroleum is produced from the Licence Area, and thereafter not later than seven days after the end of every succeeding Calendar Month, prepare and submit to the Minister a production statement containing the following particulars in each respect of each Production Area in the Licence Area and for the Licence Area:
|
(a)
|
The quantity, grades and gravity of Crude Oil Produced and Saved;
|
(b)
|
the quantity and composition of Natural Gas Produced and Saved;
|
(c)
|
the quantities of Crude Oil and Natural Gas used for purposes of carrying on drilling and Production Operations and pumping to field storage, as well as quantities injected into the formations, each such use to be separately identified;
|
(d)
|
the quantity of Petroleum unavoidably lost;
|
(e)
|
the quantity of Natural Gas flared;
|
(f)
|
the size of Petroleum stocks held at the beginning of the Calendar Month in question;
|
(g)
|
the size of Petroleum stocks held at the end of the Calendar Month in question;
|
(h)
|
the number of days in the Calendar Month during which Petroleum was produced from each Production Area in the Licence Area.
|
11.2
|
The Minister may by notice in writing addressed and delivered to the Company direct that any other particulars relating to Petroleum Operations be included
|
11.3
|
The Company shall, not later than seven days after the end of each Quarter address and deliver to the Commissioner aggregated statements containing the particulars referred to in items (a) to (h) of paragraph 11.1 in respect of the three months comprising that Quarter.
|
12.1
|
The Company shall, for purposes of clause 15 of the Agreement, prepare a statement providing calculations of the value of each quality of Namibian Crude Oil Produced and Saved from the Licence Area during each Quarter which shall contain the following information:
|
(a)
|
The quantities of Namibian Crude Oil sold at arms length during the Quarter in question by the Company, the prices realized and receipts obtained for such sales;
|
(b)
|
the quantities of Namibian Crude Oil sold other than to third parties during the Quarter in question by the Company, the prices realised and receipts obtained for such sales;
|
(c)
|
the quantities of Crude Oil appropriated by the Company to refining or other processing without being otherwise disposed of in the form of Crude Oil;
|
(d)
|
the quantity and value of stocks of Crude Oil held at the beginning of the Quarter in question;
|
(e)
|
the quantity and value of stocks of Crude Oil held at the end of the Quarter in question;
|
(f)
|
the percentage volume of total sales of Namibian Crude Oil made by the Company during the Quarter that are arms length sales to third parties other than sales made pursuant to clause 24 of the Agreement;
|
(g)
|
the percentage volume of total sales of Namibian Crude Oil made by the Company during the Quarter that are arms length sales to third parties pursuant to clause 24 of the Agreement;
|
(h)
|
the Company’s estimate, pursuant to clause 15 of the Agreement, of the market price of Namibian Crude Oil Produced and Saved for the Quarter;
|
(i)
|
all other information available to the Company, if relevant for the purposes of clause 15 of the Agreement, concerning the prices of the selection of major competitive crude oils, including contract
|
12.2
|
At the time of the development of the first Discovery of Natural Gas, the Minister and the Company shall agree on an appropriate format for reporting the value of Natural Gas sold or disposed of.
|
12.3
|
The value of production and pricing statement for each Quarter shall be submitted to the Commissioner not later than 15 days after the end of the Quarter to which such value of production and pricing statement relate.
|
13.1
|
The Company shall prepare in respect of each Calendar Month a statement of expenditure and receipts under the Agreement. The statement will distinguish between exploration expenditure, development expenditure and production expenditure and shall separately identify major items of expenditure within those categories. The statement of receipts shall distinguish between income from the sale of Petroleum and miscellaneous income of the sort itemised in paragraph 9.4 of this Annexure. if the Minister is not satisfied with the degree of disaggregation within the said categories, he may request a more detailed disaggregation and the Company shall comply promptly with such request. The statement will show the following:‑
|
(a)
|
Actual expenditure and receipts for the Calendar Month in question.
|
(b)
|
Cumulative expenditure and receipts for the budget year in question.
|
(c)
|
Latest forecast of cumulative expenditure and receipts at the Calendar Year end.
|
(d)
|
Variations between budget forecast and latest forecast, with explanations thereof.
|
13.2
|
At the end of each Quarter aggregated statements in respect of the three months comprising that Quarter shall be submitted for each of the items (a) to (d) in paragraph 13.1 above.
|
13.3
|
The statement of expenditure and receipts for each Calendar Month or Quarter shall be submitted to the Minister no later than 15 days after the end of such Calendar Month or Quarter.
|
14.1
|
The Company shall prepare with respect to each Calendar Year an additional profits tax statement containing the following information:
|
(a)
|
The value of net cash receipts for the Calendar Year, identifying separately each of the categories of gross income and allowable deductions provided in the Taxation Act.
|
(b)
|
The appropriate value of the Price Index for the Calendar Year.
|
(c)
|
The value of the first accumulated net cash position, second accumulated net cash position and the third accumulated net cash position for the tax year.
|
(d)
|
The value of the first accumulated net cash position, the second accumulated net cash position and the third accumulated net cash position at the end of the preceding tax year.
|
(e)
|
The amount of additional profits tax payable with respect to the first accumulated net cash position, the second accumulated net cash position and the third accumulated net cash position for the tax year.
|
(f)
|
The total amount of additional profits tax payable for the tax year.
|
14.2
|
The information required in terms of paragraph 14.1 shall be presented in sufficient detail so as to enable the Minister to verify the timing and amount of additional profits tax payments.
|
14.3
|
The Government reserves the right to call for additional profits tax statements more frequently than annually in order to satisfy the objective set out in paragraph 14.2 above.
|
14.4
|
The additional profits tax statement for each tax year shall be submitted to the Minister no later than 60 days after the end of such Calendar Year.
|
15.1
|
The Company shall prepare a definitive end-of-year statement. The statement shall contain aggregated information for the Calendar Year in the same format as required in the production statement, the value of production and pricing statement, and the expenditure and receipts statement, but will be based on actual quantities of Petroleum produced, income received and expenditure incurred.
|
15.2
|
The end-of-year statement for each Calendar Year shall, except in the case of the production statement, be submitted to the Minister within 60 days of the end of such Calendar Year. The end-of-year production statement shall be submitted within 14 days of the end of each Year.
|
16.1
|
The Company shall prepare an annual budget statement. This statement shall distinguish between exploration expenditure, development expenditure, and production expenditure and shall show the following:
|
(a)
|
Forecast expenditure and receipts for the Calendar Year under the Agreement.
|
(b)
|
Cumulative expenditure and receipts to the end of the said Calendar Year.
|
(c)
|
A schedule showing the most important and individual items of expenditure for the said Calendar Year.
|
(d)
|
A schedule indicating the planned expenditure on the purchase of Namibian goods and services pursuant to clause 23 of the Agreement.
|
16.2
|
The budget statement shall be submitted to the Minister with respect to each budget year no less than 90 days before the start of the Calendar Year except in the case of the Calendar Year in which the date on which the Agreement has been signed falls, when the budget statement shall be submitted within 30 days of the date on which the Agreement has been signed.
|
17.1
|
In furtherance of the obligation in clause 23 of the Agreement for the Company to purchase Namibian goods and services the Company shall prepare in respect of each Calendar Year a local procurement statement, containing the following information:
|
(a)
|
The amount of expenditure incurred by the Company directly, or indirectly through its sub-contractors, on goods supplied, produced or manufactured in Namibia;
|
(b)
|
the amount of expenditure incurred by the Company directly, or indirectly through its sub-contractors, on services provided by Namibian entities;
|
(c)
|
the respective percentages that the expenditures recorded under items (a) and (b) above represent of the Company’s total expenditures;
|
(d)
|
a detailed description of the procedures adopted during the Year to identify and purchase goods and services from Namibian suppliers; and
|
(e)
|
a detailed exposition of how the local purchases for the Year as recorded under items (a) and (b) above compared with the projected purchases included in the budget statement for that Year (pursuant to item (d) of subparagraph 16.1 of this Annexure), with explanations for any significant variations;
|
17.2
|
The local procurement statement shall be submitted to the Minister within 60 days after the end of each Calendar Year.
|
18.1
|
In furtherance of its obligation to decommission facilities used in Petroleum Operations in accordance with the Decommissioning Plan, the Company shall prepare in respect of each Calendar Year after the grant of a Production Licence a decommissioning statement, containing the following information valid as at the end of the Year:
|
(a)
|
where applicable, total cumulative production of Petroleum from the Production Area;
|
(b)
|
estimated total recoverable reserves of Petroleum from the Production Area;
|
(c)
|
the estimated date by which 50% of the estimated total recoverable reserves of Petroleum from the Production Area will have been produced;
|
(d)
|
the estimated future total cost of decommissioning the facilities in the Production Area, and of any facilities outside the Production Area;
|
(e)
|
where applicable, the amount to be deposited by the Company into any relevant Trust Fund in respect of the Year, setting out how the amount has been calculated;
|
(f)
|
where applicable, the amount actually paid into the Trust Fund by the Company in respect of the Year;
|
(g)
|
where applicable, the amount of expenditure incurred by the Company on actually decommissioning the facilities in the Year; and
|
(h)
|
where applicable, the amount of any money received by the Company in the Year from the Trust Fund.
|
18.2
|
The decommissioning statement for each relevant Calendar Year shall be submitted by the Company to the Commissioner not later than 30 days after the end of the Year.
|
(a)
|
unconditionally and irrevocably guarantees to the Government that it will make available or cause to be made available to the Company or any other directly or indirectly owned subsidiary or Affiliate of the Guarantor to which any part or, all of the Company’s rights or interest under the Agreement may subsequently be assigned (“Affiliated assignee”), resources required to ensure that the Company or an Affiliated assignee can carry out its obligations as set forth in the Agreement;
|
(b)
|
unconditionally and irrevocably guarantees to the Government the due and punctual compliance by the Company (or Affiliated assignee) with any obligations of the Company (or Affiliated assignee) under the Agreement;
|
(c)
|
undertakes to the Government that if the Company (or any Affiliated assignee) defaults on any of its obligations under the Agreement, then the Guarantor will fulfill or cause to be fulfilled the said obligations in place of the Company (or any Affiliated assignee);
|
(d)
|
declares that this guarantee shall expire on termination of the Agreement and any claims arising out of events during the period of validity of this guarantee must be submitted to the undersigned not later than 30 months subsequent to the date the claim arose.
|
1
|
The total amount of training support offered by the applicant in terms of the requirements of section 14(b) of the Petroleum (Exploration and Production) Act, 1991, as amended by the Petroleum (Exploration and Production) Amendment Act, 1993, will be subdivided into two parts, to be allocated to:
|
1.1
|
Attachments and in-house training - 30 per cent,
|
1.2
|
Institution building, scholarships, and science, engineering and technology promotion - 70 per cent.
|
Objectives:
|
To train Namibian citizens in the field of natural science, engineering and technology as related to oil and gas exploration and production, by exposing them to company practice and operation.
|
2.1
|
Recommended Fields of attachments and in-house training Geology and geophysics related to oil exploration and production Construction and reservoir engineering Drilling practice and technology Oil production practice and technology Economics of oil exploration and production
|
2.2
|
Recruitment of candidates
|
2.3
|
Reporting on training activities
|
Objective:
|
To strengthen Namibian research, education and training institutions by providing infrastructure to enhance the quality of such research education and training.
|
3.1
|
Nomination of institutions
|
3.2
|
Allocation of funds
|
3.3
|
Reporting by beneficiaries
|
Objective:
|
To enhance education and training in natural science, mathematics, engineering, and, technology in Namibia by improvement of the quality and quantity of teaching staff in these subjects in secondary schools as well as in post-school institutions. To strengthen the core of Namibians engaged in the professions of natural science, engineering and technology outside teaching.
|
4.1
|
Recruitment
|
4.2
|
The Board of Trustees of. PETROFUND shall select the candidates on merit with due regard to the medium- and short-term requirements of the country so as to create a balanced supply of natural scientists, engineers and technologists
|
Objective:
|
To foster awareness of and promote knowledge of natural science, mathematic.s, engineering and technology over a broad spectrum of the population by exposing them to selected promotional activities in the • relevant•fields.
|
5.1
|
The Board of Trustees of PETROFUND shall be responsible for an ongoing programme of promotion of natural science, engineering and technology through the organization of lectures, conferences, workshops, short courses, Olympiads, competitions etc. The target group of the population should range from primary schools right through to qualified professionals.
|
1.
|
The amounts paid under clause 11.15 of this agreement to NAMCOR will be fully accounted for by NAMCOR and will be fully audited by NAMCOR’s auditors. The allocation and utilisation of these funds will be decided upon by NAMCOR in consultation with all oil exploration/production licensees and representatives from the Ministry of Fisheries and Marine Resources and the Ministry of the Environment and Tourism. Funds will be used, amongst other purposes, for:
|
(a)
|
collecting weather and drifter buoy data needed for reliable oil spill drift modelling and for effective oil spill contingency planning;
|
(b)
|
long-term collecting of wave and current data;
|
(c)
|
long-term collecting of marine and weather data that will be needed for design of offshore installations;
|
(d)
|
periodic monitoring of levels of pollution during production drilling and production using internationally accepted methods of monitoring;
|
(e)
|
any other environment-related studies that the government ministries or the lidensees feel are needed and relevant.
|
1.
|
Any reference in the Agreement to Signet or Cricket if context allows shall be read as and be deemed to be a reference to Shell Namibia Upstream B.V.
|
2.
|
Any reference to “Company”, when used in capital letters, shall be read as and be deemed to be a reference to the term “Companies” as defined hereinafter.
|
3.
|
All other capitalised terms used herein shall have the meaning ascribed to them in the Agreement, unless they are otherwise defined in this Addendum.
|
4.
|
The Agreement is amended as follows:
|
4.1.
|
By deleting clause 1.1(j) and replacing it as follows:
|
“(j)
|
“Companies” means, at the Signature Date, Shell Namibia Upstream B.V. and NAMCOR, and includes any other entity or person to whom either Shell Namibia Upstream B.V. and NAMCOR subsequently have assigned any interest or part thereof in relation to the Exploration Licence or the Production Licence jointly held by them.”
|
4.2.
|
By inserting a new clause 1.1(fff) to read as follows:
|
“(fff)
|
“Joint operating Agreement or JOA” means the agreement defined as such in clause 14A of this Agreement;”
|
4.3.
|
By deleting clauses 2.1a to 2.1c and replacing them as follows:
|
“2.1a
|
Shell Namibia Upstream B.V. is duly registered and incorporated in accordance with the Jaws of Netherlands on 10 August 2012.
|
2.1b
|
The registered address of the head office of Shell Namibia Upstream B.V. is Carel van Bylandtlaan 30, The Hague 2596 HR, the Netherlands.
|
2.1c
|
Shell Namibia Upstream B. V. hereby declares that the following persons are the beneficial owners of more than five per cent of the shares issued by it:-
|
4.4.
|
By deleting clause 2.2 in its entirety.
|
4.5.
|
By substituting numbering of clause 2.3a to 2.3c with 2.2a to 2.2c.
|
4.6.
|
By deleting clause 10.2 and replacing it as follows:
|
“10.2
|
A notice referred to in clause 10.1 shall be given as early as possible prior to or during the drilling of the Well, but in any case not after the Company has notified the Minister of the detailed completion or abandonment plan for the Well. Upon receipt of such notice the Company shall, subject to the terms of clause 10.5, cause such tests, penetration and drilling to be carried out at the sole cost and risk of the Government, unless such activities interfere with Petroleum Operations to be carried out pursuant to this Agreement. At any time before such tests, penetration or drilling is carried out the Company may elect to include such tests, penetration or drilling In its Exploration Operations.”
|
4.7.
|
By deleting the word “
unreasonably
” in the first sentence of clause 10.3(b).
|
4.8.
|
By inserting the following after clause 11.8:
|
“11.8A
|
The Parties agree that for offshore seismic and drilling operations any required impact assessment studies need to be completed according to internationally recognised standards.”
|
4.9.
|
By deleting clause 12.5 and replacing it as follows:
|
“12.5
|
Where the Company consists of more than one company-
|
(a)
|
all the terms and obligations of this Agreement shall apply to each one of such companies jointly and severally;
|
(b)
|
Shell shall be the operator and the company who shall carry on the Petroleum Operations of the Company under this Agreement in accordance with the terms of the JOA. unless the Commissioner pursuant to an application in writing addressed and delivered to him approves a change of operator, in which event the other operator so approved of shall be deemed to be the operator from the date of such approval;
|
(c)
|
the JOA entered into by or between such companies shall be consistent with the provisions of this Agreement and shall be in writing and a copy of each such agreement shall be submitted to the Commissioner not later than ten days after the date of signature thereof.”
|
4.10.
|
By inserting the words “
in accordance with the JOA
” between the words “
for
” and “
and
” in the last sentence of clause 12.6.
|
4.11.
|
By inserting a new clause 13.3 to read as follows:
|
“
13.3
|
With the approval of the Minister of Finance, the Companies may be allowed to keep petroleum expenditure in United States dollars for Income Tax purposes until such time when commercial production is commenced. This is without any prejudice to any of the provisions contained in the Petroleum Tax Act.
”
|
4.12.
|
By deleting clause 14A and replacing it as follows
|
14.A.1
|
NAMCOR shall be carried by the carrying party(ies) on a 10% interest stake in the Block subject to and in accordance with the terms and conditions contained in the Joint Operating Agreement to be entered between Namcor and Shell (the “JOA”, as defined), so long as there is no Material Adverse Change, as defined in the JOA.
|
14.A.2
|
The Government hereby acknowledges that the Petroleum Operations shall be performed by the Companies in accordance with the terms of the JOA, and the Government recognises the respective rights and obligations of the parties under the JOA, which shall be deemed to incorporated by reference into this Agreement.”
|
4.13.
|
By inserting new clauses 15.7 and 15.8 to read as follows:
|
“
15.7
|
For the avoidance of doubt, any information provided in accordance with this Clause 15 shall always be subject to any limitations placed on either Party as a result of any applicable confidentiality and/or market and/or legal restrictions (including but not limited to any restrictions relating to the disclosure by one Party to the other of commercially sensitive information).
|
15.8
|
Notwithstanding anything to the contrary contained herein, the mechanism for establishing the market value of Namibian Crude Oil shall be set out in the JOA detailing, inter alia, that the market value of Namibian Crude Oil shall be determined on a Calendar Month basis as follows:-
|
(i)
|
The average of the mean of Dated Brent quotations as published in Platts Crude Oil Marketwire for all published quotations during the actual Calendar Month of loading (i.e. the Calendar Month in which the Bill of Lading date occurs); plus
|
(ii)
|
A differential to Dated Brent to be established pursuant to the terms of the JOA, which will incorporate a formula that allows for adjustment of the differential to take account of differences in quality/yield, quantity, transportation costs, delivery time, payment and other contract terms between Namibian Crude Oil and other major competitive crude oils of generally similar quality that are to be agreed upon between the Company and the Minister.”
|
4.14.
|
By inserting the words “
acts of the Government,
” between the words “
God,
” and “
unavoidable
” in the second line, and the word “
reasonable
” between the words “
the
” and “
control
” in the fifth line of clause 27 .3.
|
4.15.
|
By deleting the words “
the British Institute of Petroleum
” in clause 29.6 and replacing them with “
the Energy Institute
”.
|
4.16.
|
By deleting clause 33 and replacing it as follows:
|
4.17.
|
By deleting the address stated under clause 35.1(c)(i) and replacing it with the following:
|
4.18.
|
By deleting the address stated under clause 35.3(b) and replacing it with the following:
|
4.19.
|
By deleting the two numbers “
35.4
” in clause 36.3 and replacing them with the numbers “
36.4
”.
|
4.20.
|
By deleting the description of the licence area in Annexure 1 and replacing it as follows:
|
Coordinate Reference System name:
|
WGS84
|
Geodetic datum name:
|
World Geodetic System 1984
|
Ellipsoid name:
|
WGS 84
|
Ellipsoid semi major axis (a):
|
6378137 m
|
Ellipsoid inverse flattening (1/f):
|
298.2572236
|
Point
|
Longitude
|
Latitude
|
Line from – to
|
Line type
|
A
|
13
o
30' 00.0" E
|
29
o
00' 00.0" S
|
|
|
|
|
|
A –
B
|
Parallel
|
B
|
14
o
00' 00.0" E
|
29
o
00' 00.0" S
|
|
|
|
|
|
B –
C
|
Meridian
|
C
|
14
o
00' 00.0" E
|
29
o
30' 00.0" S
|
|
|
|
|
|
C –
D
|
Parallel
|
D
|
15
o
00' 00.0" E
|
29
o
30' 00.0" S
|
|
|
|
|
|
D –
E
|
Meridian
|
E
|
15
o
00' 00.0" E
|
Intersection of line going South from D (having constant longitude) with international boundary between Namibia and South Africa
|
|
|
|
|
|
E –
F
|
International boundary between Namibia and South Africa
|
F
|
13
o
30' 00.0" E
|
Intersection of line going South from A (having constant longitude) with international boundary between Namibia and South Africa
|
|
|
|
|
|
F –
A
|
Meridian
|
A
|
13
o
30' 00.0" E
|
29
o
00' 00.0" S
|
|
|
4.21.
|
By deleting the map in Annexure 2 and replacing it as follows:
|
4.22.
|
By deleting the words “
Alpha Petro (pty) Ltd. (hereinafter referred to as “the Company”
” in clause 1 of Annexure 4 and replacing them with the reference “
Companies
”.
|
4.23.
|
By deleting clause 15.2 of Annexure 4 and replacing it as follows:
|
“15.2
|
The preliminary end of year statement for each Calendar Year shall be submitted to the Minister within 14 days of the end of such Calendar Year. The final end-of-year statements shall be submitted within 60 days of the end of each Year.”
|
4.24.
|
By deleting the number “
11.15
” in clause 1 of Annexure 7 and replacing it with the reference “
11.16(b)(viii)
”.
|
/s/ Isak Katali
|
THE GOVERNMENT OF THE REPUBLIC OF NAMIBIA
|
THE MINISTER OF MINES AND ENERGY
|
/s/ Dennis Zekveld
|
SHELL NAMIBIA UPSTREAM B.V.
|
NAME:
|
/s/ Mbuipaha Kandjoze
|
NATIONAL PETROLEUM CORPORATION OF NAMIBIA
|
NAME:
|
1.
|
All other capitalised terms used herein shall have the meaning ascribed to them in the Agreement, unless they are otherwise defined in this Addendum.
|
2.
|
The Agreement is amended as follows:
|
2.1.
|
By deleting clause 4.1 (b) and replacing it as follows:
|
(A)
|
Continuation of PEL39 dilution workstream on a reasonable efforts basis and technical work to further evaluate the subsurface potential and mature additional prospectivity;
|
(B)
|
Conduct an environmental impact assessment for drilling of a deep-water exploration well; and
|
(C)
|
Maintain Shell Namibia Upstream B. V. in-country presence with continued participation in the oil and gas industry through the Namibian Petroleum Operators Association and, subject to Shell’s internal processes and mandatory procedures, continuation of social investment programmes
|
2.2.
|
By deleting clause 14.2 and replacing it as follows:
|
“14.2
|
The rate at which additional profits tax shall be levied on the Company under section 21 (b)(ii) of the Taxation Act in relation to the second accumulated net cash position shall be 3 (three) per cent.”
|
2.3.
|
By deleting clause 14.3 and replacing it as follows:
|
“14.3
|
The rate at which additional profits tax shall be levied on the Company under section 21 (c)(ii) of the Taxation Act in relation to the third accumulated net cash position shall be 4 (four) per cent.
|
2.4.
|
By inserting a new clause 22. 7 to read as follows:
|
–
|
Health, safety, security, environment and sustainable development for oil & gas
|
–
|
Petroleum project management
|
–
|
Orange Basin subsurface analysis
|
–
|
Field development planning
|
–
|
Specialist subsurface training
|
/s/ Obeth Mbuipaha Kandjoze
|
THE GOVERNMENT OF THE REPUBLIC OF NAMIBIA
|
THE MINISTER OF MINES AND ENERGY
|
/s/ Dennis Zekveld
|
SHELL NAMIBIA UPSTREAM B.V.
|
NAME: Dennis Zekveld
|
/s/ Immanuel Mulunga
|
NATIONAL PETROLEUM CORPORATION OF NAMIBIA
|
NAME: Immanuel Mulunga
|
Subsidiary
|
Jurisdiction of Incorporation
|
Kosmos Energy Ltd.
|
Delaware
|
Kosmos Energy Delaware Holdings, LLC
|
Delaware
|
Kosmos Energy Holdings
|
Cayman Islands
|
Kosmos Energy LLC
|
Texas
|
Kosmos Energy Operating
|
Cayman Islands
|
Kosmos Energy Ventures
|
Cayman Islands
|
Kosmos Energy South Atlantic
|
Cayman Islands
|
Kosmos Energy Latin America
|
Cayman Islands
|
Kosmos Energy Brasil Oleo e Gas Ltda.
|
Brazil
|
Kosmos Energy Deepwater Morocco
|
Cayman Islands
|
Kosmos Energy Cameroon HC
|
Cayman Islands
|
Kosmos Energy Offshore Morocco HC
|
Cayman Islands
|
Kosmos Energy Finance International
|
Cayman Islands
|
Kosmos Energy Finance
|
Cayman Islands
|
Kosmos Energy International
|
Cayman Islands
|
Kosmos Energy Development
|
Cayman Islands
|
Kosmos Energy Ghana HC
|
Cayman Islands
|
Kosmos Energy Suriname
|
Cayman Islands
|
Kosmos Energy Ireland
|
Cayman Islands
|
Kosmos Energy Mauritania
|
Cayman Islands
|
Kosmos Energy Sierra Leone
|
Cayman Islands
|
Kosmos Energy Equatorial Guinea
|
Cayman Islands
|
Kosmos Energy Credit International
|
Cayman Islands
|
FATE Energy Services
|
Cayman Islands
|
Kosmos Energy Operating Service SARL
|
Morocco
|
Kosmos Energy Liberia
|
Cayman Islands
|
Kosmos Energy Portugal
|
Cayman Islands
|
Kosmos Energy Senegal
|
Cayman Islands
|
Kosmos Energy Global Supply
|
Cayman Islands
|
Kosmos Energy Sao Tome and Principe
|
Cayman Islands
|
Kosmos Energy Maroc Mer Profonde
|
Cayman Islands
|
Kosmos Energy Congo
|
Cayman Islands
|
Kosmos Energy Cote d’Ivoire
|
Cayman Islands
|
Kosmos Energy Namibia
|
Cayman Islands
|
Kosmos Energy GOM Holdings, LLC
|
United States of America
|
Kosmos Energy Gulf of Mexico, LLC
|
United States of America
|
Kosmos Energy Gulf of Mexico Management, LLC
|
United States of America
|
Kosmos Energy Gulf of Mexico Operations, LLC
|
United States of America
|
Houston Energy Deepwater Ventures
|
United States of America
|
Kosmos Energy Investments Senegal Limited
|
United Kingdom
|
Kosmos-Trident International Petroleum, Inc.
|
Cayman Islands
|
|
|
|
/s/ Ernst & Young LLP
|
1.
|
I have reviewed this annual report on Form 10‑K of Kosmos Energy Ltd.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date: February 28, 2019
|
/s/ Andrew G. Inglis
|
|
Andrew G. Inglis
Chairman of the Board of Directors and
Chief Executive Officer (Principal Executive Officer)
|
1.
|
I have reviewed this annual report on Form 10‑K of Kosmos Energy Ltd.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a‑15(f) and 15d‑15(f)) for the registrant and have:
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
Date: February 28, 2019
|
/s/ Thomas P. Chambers
|
|
Thomas P. Chambers
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
Date: February 28, 2019
|
/s/ Andrew G. Inglis
|
|
Andrew G. Inglis
Chairman of the Board of Directors and Chief Executive Officer
(Principal Executive Officer)
|
(1)
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
Date: February 28, 2019
|
/s/ Thomas P. Chambers
|
|
Thomas P. Chambers
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
|
\s\ Tosin Famurewa
|
Tosin Famurewa, P.E., S.P.E.C.
|
TBPE License No. 100569
|
Managing Senior Vice President
|
\s\ Christine E. Neylon
|
|
\s\ Victor Abu
|
Christine E. Neylon, P.E.
|
|
Victor Abu, P.E.
|
TBPE License No. 122128
|
|
TBPE License No. 132717
|
Vice President
|
|
Senior Petroleum Engineer
|
SEC PARAMETERS
|
|
||||||||||||||||
Estimated Net Reserves and Income Data
|
|
||||||||||||||||
Attributable to Certain Interests of
|
|
||||||||||||||||
Kosmos Energy Limited
|
|
||||||||||||||||
As of December 31, 2018
|
|
||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
|
Proved
|
|||||||||||||||
|
|
Developed
|
|
|
|
|
|||||||||||
|
|
Producing*
|
|
Non-Producing
|
|
Undeveloped
|
|
Total
|
|||||||||
Gulf of Mexico Project Area
|
|
|
|
|
|
|
|
|
|||||||||
Net Reserves
|
|
|
|
|
|
|
|
|
|||||||||
Oil/Condensate – Mbbl
|
|
24,310
|
|
|
6,224
|
|
|
10,219
|
|
|
40,753
|
|
|||||
Plant Products – Mbbl
|
|
1,843
|
|
|
709
|
|
|
1,514
|
|
|
4,066
|
|
|||||
Sales Gas – MMcf
|
|
17,916
|
|
|
6,670
|
|
|
13,301
|
|
|
37,887
|
|
|||||
Fuel Gas – MMcf
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|||||
|
|
|
|
|
|
|
|
|
|||||||||
Income Data ($M)
|
|
|
|
|
|
|
|
|
|||||||||
Future Gross Revenue
|
|
|
$1,730,895
|
|
|
|
$456,158
|
|
|
|
$763,594
|
|
|
$
|
2,950,647
|
|
|
Deductions
|
|
358,355
|
|
|
114,403
|
|
|
332,728
|
|
|
805,486
|
|
|||||
Future Net Income (FNI)
|
|
|
$1,372,540
|
|
|
|
$341,755
|
|
|
|
$430,866
|
|
|
$
|
2,145,161
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Discounted FNI @ 10%
|
|
|
$1,150,208
|
|
|
|
$228,111
|
|
|
|
$292,879
|
|
|
$
|
1,671,198
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Greater Jubilee and TEN Project Areas
|
|
|
|
|
|
|
|||||||||||
Net Reserves
|
|
|
|
|
|
|
|
|
|||||||||
Oil/Condensate – Mbbl
|
|
48,376
|
|
|
0
|
|
|
33,489
|
|
|
81,865
|
|
|||||
Plant Products – Mbbl
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
|||||
Sales Gas – MMcf
|
|
13,406
|
|
|
0
|
|
|
14,312
|
|
|
27,718
|
|
|||||
Fuel Gas – MMcf
|
|
19,137
|
|
|
0
|
|
|
0
|
|
|
19,137
|
|
|||||
|
|
|
|
|
|
|
|
|
|||||||||
Income Data ($M)
|
|
|
|
|
|
|
|
|
|||||||||
Future Gross Revenue
|
|
|
$3,468,032
|
|
|
|
$0
|
|
|
|
$2,404,126
|
|
|
$
|
5,872,158
|
|
|
Deductions
|
|
1,194,874
|
|
|
0
|
|
|
1,344,630
|
|
|
2,539,504
|
|
|||||
Future Net Income (FNI)
|
|
|
$2,273,158
|
|
|
|
$0
|
|
|
|
$1,059,496
|
|
|
$
|
3,332,654
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Discounted FNI @ 10%
|
|
|
$1,655,007
|
|
|
|
$0
|
|
|
$
|
593,315
|
|
|
$
|
2,248,322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
||||||||||||||
|
|
Developed
|
|
|
|
|
||||||||||
|
|
Producing*
|
|
Non-Producing
|
|
Undeveloped
|
|
Total
|
||||||||
Ceiba and Okume Project Areas
|
|
|
|
|
|
|
|
|
||||||||
Net Reserves
|
|
|
|
|
|
|
|
|
||||||||
Oil/Condensate – Mbbl
|
|
20,922
|
|
|
2,427
|
|
|
879
|
|
|
24,228
|
|
||||
Plant Products – Mbbl
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
||||
Sales Gas – MMcf
|
|
0
|
|
|
0
|
|
|
0
|
|
|
0
|
|
||||
Fuel Gas – MMcf
|
|
13,981
|
|
|
0
|
|
|
0
|
|
|
13,981
|
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Income Data ($M)
|
|
|
|
|
|
|
|
|
||||||||
Future Gross Revenue
|
|
|
$1,478,925
|
|
|
|
$171,591
|
|
|
|
$62,130
|
|
|
|
$1,712,646
|
|
Deductions
|
|
824,634
|
|
|
83,355
|
|
|
47,748
|
|
|
955,737
|
|
||||
Future Net Income (FNI)
|
|
$
|
654,291
|
|
|
$
|
88,236
|
|
|
|
$14,382
|
|
|
$
|
756,909
|
|
|
|
|
|
|
|
|
|
|
||||||||
Discounted FNI @ 10%
|
|
$
|
603,217
|
|
|
$
|
72,281
|
|
|
|
$12,984
|
|
|
$
|
688,482
|
|
|
|
|
|
|
|
|
|
|
||||||||
Total
|
|
|
|
|
|
|
|
|
||||||||
Net Reserves
|
|
|
|
|
|
|
|
|
||||||||
Oil/Condensate – Mbbl
|
|
93,608
|
|
|
8,651
|
|
|
44,587
|
|
|
146,846
|
|
||||
Plant Products – Mbbl
|
|
1,843
|
|
|
709
|
|
|
1,514
|
|
|
4,066
|
|
||||
Sales Gas – MMcf
|
|
31,322
|
|
|
6,670
|
|
|
27,613
|
|
|
65,605
|
|
||||
Fuel Gas – MMcf
|
|
33,118
|
|
|
0
|
|
0
|
|
|
33,118
|
|
|||||
|
|
|
|
|
|
|
|
|
||||||||
Income Data ($M)
|
|
|
|
|
|
|
|
|
||||||||
Future Gross Revenue
|
|
|
$6,677,852
|
|
|
|
$627,749
|
|
|
|
$3,229,850
|
|
|
|
$10,535,451
|
|
Deductions
|
|
2,377,863
|
|
|
197,758
|
|
|
1,725,106
|
|
|
4,300,727
|
|
||||
Future Net Income (FNI)
|
|
|
$4,299,989
|
|
|
|
$429,991
|
|
|
|
$1,504,744
|
|
|
$
|
6,234,724
|
|
|
|
|
|
|
|
|
|
|
||||||||
Discounted FNI @ 10%
|
|
|
$3,408,432
|
|
|
|
$300,392
|
|
|
$
|
899,178
|
|
|
$
|
4,608,002
|
|
|
|
Discounted Future Net Income
|
||
|
|
As of December 31, 2018
|
||
Discount Rate
|
|
Total
|
|
|
Percent
|
|
Proved
|
|
|
|
|
|
|
|
5
|
|
$5,309,242
|
|
|
15
|
|
$4,063,980
|
|
|
20
|
|
$3,632,847
|
|
|
25
|
|
$3,284,653
|
|
•
|
future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves.
|
•
|
future production rates were projected based on a type well derived from analogy to surrounding historical well production.
|
•
|
future production rates were based on a combination of historical performance data, volumetric analysis and a robust numerical simulation model. Future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated “simulation based decline rate” was then applied until depletion of the reserves.
|
Geographic Area
|
Product
|
Price
Reference
|
Average
Benchmark
Price
|
Average Realized
Price
|
West Africa
|
|
|
|
|
Greater Jubilee and TEN Project Areas
|
Oil
|
Brent
|
$71.54/BBL
|
$71.53/BBL
|
Gas
|
Contract
|
$0.60/MCF
|
$0.60/MCF
|
|
|
|
|
|
|
Central Africa
|
|
|
|
|
Ceiba and Okume Project Areas
|
Oil
|
Brent
|
$71.54/BBL
|
$70.69/BBL
|
|
|
|
|
|
North America
|
|
|
|
|
Gulf of Mexico Project Area
|
Oil/
Condensate
|
Heavy Louisiana Sweet
|
$70.20/BBL
|
$67.81/BBL
|
NGLs
|
Heavy Louisiana Sweet
|
$70.20/BBL
|
$25.83/BBL
|
|
Gas
|
Henry Hub
|
$3.10/MMBTU
|
$2.17/MCF
|
(1)
|
completion intervals that are open at the time of the estimate but which have not yet started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|