KOSMOS ENERGY LTD.
10-Ks and 10-Qs
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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(Mark One)
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☒
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the quarterly period ended
June 30, 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
Commission file number: 001-35167
Kosmos Energy Ltd.
(Exact name of registrant as specified in its charter)
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Bermuda
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98-0686001
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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Identification No.)
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Clarendon House
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2 Church Street
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Hamilton, Bermuda
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HM 11
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(Address of principal executive offices)
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(Zip Code)
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Registrant’s telephone number, including area code:
+1 441 295 5950
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer ☒
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Accelerated filer ☐
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Non-accelerated filer ☐
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Smaller reporting company ☐
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(Do not check if a smaller reporting company)
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Emerging growth company ☐
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
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Class
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Outstanding at August 1, 2018
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Common Shares, $0.01 par value
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398,403,309
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TABLE OF CONTENTS
Unless otherwise stated in this report, references to “Kosmos,” “we,” “us” or “the company” refer to Kosmos Energy Ltd. and its wholly owned subsidiaries. We have provided definitions for some of the industry terms used in this report in the “Glossary and Selected Abbreviations” beginning on page 3.
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Page
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PART I. FINANCIAL INFORMATION
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PART II. OTHER INFORMATION
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2
KOSMOS ENERGY LTD.
GLOSSARY AND SELECTED ABBREVIATIONS
The following are abbreviations and definitions of certain terms that may be used in this report. Unless listed below, all defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings.
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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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3
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“Dry hole”
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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.
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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 for taking on a portion of the drilling costs of one or more specific wells 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 the drilling costs of one or more specific wells 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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“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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4
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“MBbl”
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Thousand barrels of oil.
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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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“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 planned 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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5
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“Shelf margin”
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The path created by the change in direction of the shoreline in reaction to the filling of a sedimentary basin.
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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 natural 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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“Submarine fan”
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A fan-shaped deposit of sediments occurring in a deep water setting where sediments have been transported via mass flow, gravity induced, processes from the shallow to deep water. These systems commonly develop at the bottom of sedimentary basins or at the end of large rivers.
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“Three-way fault trap”
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A structural trap where at least one of the components of closure is formed by offset of rock layers across a fault.
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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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6
KOSMOS ENERGY LTD.
(In thousands, except share data)
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June 30,
2018 |
December 31,
2017 |
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(Unaudited)
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Assets
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Current assets:
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Cash and cash equivalents
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$
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116,941
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$
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233,412
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Restricted cash
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20,377
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56,380
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Receivables:
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Joint interest billings, net
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68,006
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134,565
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Oil sales
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73,700
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—
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Related party
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2,610
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780
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Other
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13,501
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25,616
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Inventories
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71,085
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71,861
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Prepaid expenses and other
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33,638
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9,306
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Derivatives
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18,053
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1,682
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Total current assets
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417,911
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533,602
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Property and equipment:
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Oil and gas properties, net
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2,253,815
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2,310,973
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Other property, net
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9,249
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6,855
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Property and equipment, net
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2,263,064
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2,317,828
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Other assets:
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Equity method investment
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151,310
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236,514
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Restricted cash
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9,168
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15,194
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Long-term receivables - joint interest billings
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28,981
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34,941
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Deferred financing costs, net of accumulated amortization of $15,320 and $13,951 at June 30, 2018 and December 31, 2017, respectively
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1,141
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2,510
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Deferred tax assets
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20,763
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22,517
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Derivatives
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10,421
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39
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Other
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684
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29,458
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Total assets
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$
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2,903,443
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$
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3,192,603
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Liabilities and shareholders’ equity
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Current liabilities:
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Accounts payable
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$
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128,471
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$
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141,787
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Accrued liabilities
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145,600
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219,412
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Derivatives
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162,329
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67,531
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Total current liabilities
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436,400
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428,730
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Long-term liabilities:
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Long-term debt, net
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1,167,775
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1,282,797
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Derivatives
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83,733
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30,209
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Asset retirement obligations
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70,122
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66,595
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Deferred tax liabilities
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392,918
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476,548
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Other long-term liabilities
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8,364
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10,612
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Total long-term liabilities
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1,722,912
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1,866,761
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Shareholders’ equity:
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Preference shares, $0.01 par value; 200,000,000 authorized shares; zero issued at June 30, 2018 and December 31, 2017
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—
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—
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Common shares, $0.01 par value; 2,000,000,000 authorized shares; 407,557,090 and 398,599,457 issued at June 30, 2018 and December 31, 2017, respectively
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4,076
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3,986
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Additional paid-in capital
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2,015,463
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2,014,525
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Accumulated deficit
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(1,226,701
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)
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(1,073,202
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)
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Treasury stock, at cost, 9,263,269 and 9,188,819 shares at June 30, 2018 and December 31, 2017, respectively
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(48,707
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(48,197
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)
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Total shareholders’ equity
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744,131
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897,112
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Total liabilities and shareholders’ equity
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$
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2,903,443
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$
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3,192,603
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See accompanying notes.
7
KOSMOS ENERGY LTD.
(In thousands, except per share data)
(Unaudited)
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Three Months Ended
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Six Months Ended
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|||||||||||||
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June 30,
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June 30,
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2018
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2017
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2018
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2017
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Revenues and other income:
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Oil and gas revenue
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$
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215,191
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$
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136,363
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$
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342,387
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$
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239,795
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Other income, net
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282
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10,161
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263
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58,695
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Total revenues and other income
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215,473
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146,524
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342,650
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298,490
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Costs and expenses:
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|||||||
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Oil and gas production
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49,815
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21,604
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96,583
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41,490
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Facilities insurance modifications, net
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1,029
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(2
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)
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9,478
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2,572
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Exploration expenses
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77,481
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19,982
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98,674
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125,696
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General and administrative
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17,497
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14,739
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39,380
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30,526
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Depletion and depreciation
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74,289
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72,441
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128,566
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107,419
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Interest and other financing costs, net
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18,870
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19,465
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44,564
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36,251
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Derivatives, net
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140,272
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(25,411
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)
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178,750
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(63,268
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)
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(Gain) loss on equity method investments, net
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(16,100
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)
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6,426
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(34,796
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)
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6,426
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Other expenses, net
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938
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2,008
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4,643
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2,770
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|||||||
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Total costs and expenses
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364,091
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131,252
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565,842
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289,882
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|||||||
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Income (loss) before income taxes
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(148,618
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)
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15,272
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(223,192
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)
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8,608
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|||||||
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Income tax expense (benefit)
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(45,345
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)
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23,739
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(69,693
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)
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45,916
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Net loss
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$
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(103,273
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)
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$
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(8,467
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)
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$
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(153,499
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)
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$
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(37,308
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)
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Net loss per share:
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|||||||
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Basic
|
$
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(0.26
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)
|
$
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(0.02
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)
|
$
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(0.39
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)
|
$
|
(0.10
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)
|
|||
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Diluted
|
$
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(0.26
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)
|
$
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(0.02
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)
|
$
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(0.39
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)
|
$
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(0.10
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)
|
|||
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Weighted average number of shares used to compute net loss per share:
|
|
|
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|
|
|
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|
|||||||
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Basic
|
396,826
|
|
387,952
|
|
396,218
|
|
387,634
|
|
|||||||
|
Diluted
|
396,826
|
|
387,952
|
|
396,218
|
|
387,634
|
|
|||||||
See accompanying notes.
8
KOSMOS ENERGY LTD.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(In thousands)
(Unaudited)
|
|
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Additional
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|
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|
||||||||||||||||
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Common Shares
|
Paid-in
|
Accumulated
|
Treasury
|
|
|||||||||||||||||
|
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Shares
|
Amount
|
Capital
|
Deficit
|
Stock
|
Total
|
||||||||||||||||
|
Balance as of December 31, 2017
|
398,599
|
|
$
|
3,986
|
|
$
|
2,014,525
|
|
$
|
(1,073,202
|
)
|
$
|
(48,197
|
)
|
$
|
897,112
|
|
|||||
|
Equity-based compensation
|
—
|
|
—
|
|
18,213
|
|
—
|
|
—
|
|
18,213
|
|
||||||||||
|
Restricted stock awards and units
|
8,958
|
|
90
|
|
(90
|
)
|
—
|
|
—
|
|
—
|
|
||||||||||
|
Purchase of treasury stock / tax withholdings
|
—
|
|
—
|
|
(17,185
|
)
|
—
|
|
(510
|
)
|
(17,695
|
)
|
||||||||||
|
Net loss
|
—
|
|
—
|
|
—
|
|
(153,499
|
)
|
—
|
|
(153,499
|
)
|
||||||||||
|
Balance as of June 30, 2018
|
407,557
|
|
$
|
4,076
|
|
$
|
2,015,463
|
|
$
|
(1,226,701
|
)
|
$
|
(48,707
|
)
|
$
|
744,131
|
|
|||||
See accompanying notes.
9
KOSMOS ENERGY LTD.
(In thousands)
(Unaudited)
|
|
Six Months Ended June 30,
|
||||||
|
|
2018
|
2017
|
|||||
|
Operating activities
|
|
|
|
|
|||
|
Net loss
|
$
|
(153,499
|
)
|
$
|
(37,308
|
)
|
|
|
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
|
|||||||
|
Depletion, depreciation and amortization
|
133,289
|
|
112,521
|
|
|||
|
Deferred income taxes
|
(81,876
|
)
|
41,017
|
|
|||
|
Unsuccessful well costs
|
44,654
|
|
3,605
|
|
|||
|
Change in fair value of derivatives
|
177,790
|
|
(58,944
|
)
|
|||
|
Cash settlements on derivatives, net (including $(57.3) million and $24.3 million on commodity hedges during 2018 and 2017)
|
(56,221
|
)
|
19,417
|
|
|||
|
Equity-based compensation
|
17,085
|
|
20,329
|
|
|||
|
Loss on extinguishment of debt
|
4,056
|
|
—
|
|
|||
|
Distributions in excess of equity in earnings
|
5,234
|
|
6,426
|
|
|||
|
Other
|
449
|
|
2,514
|
|
|||
|
Changes in assets and liabilities:
|
|||||||
|
(Increase) decrease in receivables
|
10,067
|
|
(28,251
|
)
|
|||
|
(Increase) decrease in inventories
|
800
|
|
(6,038
|
)
|
|||
|
(Increase) decrease in prepaid expenses and other
|
4,888
|
|
(17,459
|
)
|
|||
|
Decrease in accounts payable
|
(13,316
|
)
|
(131,480
|
)
|
|||
|
Increase (decrease) in accrued liabilities
|
(92,967
|
)
|
56,137
|
|
|||
|
Net cash provided by (used in) operating activities
|
433
|
|
(17,514
|
)
|
|||
|
Investing activities
|
|
|
|
|
|||
|
Oil and gas assets
|
(92,650
|
)
|
(42,805
|
)
|
|||
|
Other property
|
(2,815
|
)
|
(1,454
|
)
|
|||
|
Return of investment from KTIPI
|
79,970
|
|
—
|
|
|||
|
Proceeds on sale of assets
|
—
|
|
222,068
|
|
|||
|
Net cash provided by (used in) investing activities
|
(15,495
|
)
|
177,809
|
|
|||
|
Financing activities
|
|
|
|
|
|||
|
Payments on long-term debt
|
(100,000
|
)
|
(200,000
|
)
|
|||
|
Purchase of treasury stock / tax withholdings
|
(17,695
|
)
|
(1,945
|
)
|
|||
|
Deferred financing costs
|
(25,743
|
)
|
—
|
|
|||
|
Net cash used in financing activities
|
(143,438
|
)
|
(201,945
|
)
|
|||
|
Net decrease in cash, cash equivalents and restricted cash
|
(158,500
|
)
|
(41,650
|
)
|
|||
|
Cash, cash equivalents and restricted cash at beginning of period
|
304,986
|
|
273,195
|
|
|||
|
Cash, cash equivalents and restricted cash at end of period
|
$
|
146,486
|
|
$
|
231,545
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|||
|
Cash paid for:
|
|
|
|
|
|||
|
Interest
|
$
|
47,845
|
|
$
|
24,944
|
|
|
|
Income taxes
|
$
|
22,596
|
|
$
|
27,199
|
|
|
|
Non-cash activity:
|
|
|
|
|
|||
|
Contribution to equity method investment
|
$
|
—
|
|
$
|
133,893
|
|
|
See accompanying notes.
10
KOSMOS ENERGY LTD.
Notes to Consolidated Financial Statements
(Unaudited)
1. Organization
Kosmos Energy Ltd. was incorporated pursuant to the laws of Bermuda in January 2011 to become a holding company for Kosmos Energy Holdings. Kosmos Energy Holdings is a privately held Cayman Islands company that was formed in March 2004. As a holding company, Kosmos Energy Ltd.’s management operations are conducted through a wholly owned subsidiary, Kosmos Energy, LLC. The terms “Kosmos,” the “Company,” “we,” “us,” “our,” “ours,” and similar terms refer to Kosmos Energy Ltd. and its wholly owned subsidiaries, unless the context indicates otherwise.
Kosmos is
a pure play deepwater oil and gas company with growing production, a pipeline of development opportunities and a balanced exploration portfolio along the Atlantic Margins. Our assets include growing production offshore Ghana and Equatorial Guinea, a competitively positioned Tortue gas project in Mauritania and Senegal and a sustainable exploration program balanced between proven basins (Equatorial Guinea), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire and Sao Tome and Principe).
Kosmos is listed on the New York Stock Exchange and London Stock Exchange and is traded under the ticker symbol KOS.
We have
one
reportable segment, which is the exploration and production of oil and natural gas. Substantially all of our long-lived assets and all of our product sales are related to production located offshore Ghana. We also have an equity method investment generating revenues with operations offshore Equatorial Guinea.
2. Accounting Policies
General
The interim-period financial information presented in the consolidated financial statements included in this report is unaudited and, in the opinion of management, includes all adjustments of a normal recurring nature necessary to present fairly the consolidated financial position as of
June 30, 2018
, the changes in the consolidated statements of shareholders’ equity for the six months ended
June 30, 2018
, the consolidated results of operations for the three and
six
months ended
June 30, 2018
and
2017
, and the consolidated cash flows for the
six
months ended
June 30, 2018
and
2017
. The results of the interim periods shown in this report are not necessarily indicative of the final results to be expected for the full year. The consolidated financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (“SEC”) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by Generally Accepted Accounting Principles in the United States of America (“GAAP”) have been condensed or omitted from these interim consolidated financial statements. These consolidated financial statements and the accompanying notes should be read in conjunction with our audited consolidated financial statements for the year ended
December 31, 2017
, included in our annual report on Form 10-K.
Reclassifications
Certain prior period amounts have been reclassified to conform with the current presentation. Such reclassifications had no impact on our reported net
loss
, current assets, total assets, current liabilities, total liabilities, shareholders’ equity or cash flows.
Cash, Cash Equivalents and Restricted Cash
|
|
June 30,
2018 |
December 31,
2017 |
|||||
|
|
(In thousands)
|
||||||
|
Cash and cash equivalents
|
$
|
116,941
|
|
$
|
233,412
|
|
|
|
Restricted cash - current
|
20,377
|
|
56,380
|
|
|||
|
Restricted cash - long-term
|
9,168
|
|
15,194
|
|
|||
|
Total cash, cash equivalents and restricted cash shown in the consolidated statement of cash flows
|
$
|
146,486
|
|
$
|
304,986
|
|
|
11
Cash and cash equivalents include demand deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase.
In accordance with certain of our petroleum contracts, we have posted letters of credit related to performance guarantees for our minimum work obligations. These letters of credit are cash collateralized in accounts held by us and as such are classified as restricted cash. Upon completion of the minimum work obligations and/or entering into the next phase of the petroleum contract, the requirement to post the existing letters of credit will be satisfied and the cash collateral will be released. However, additional letters of credit may be required should we choose to move into the next phase of certain of our petroleum contracts. As of
June 30, 2018
and
December 31, 2017
, we had
$20.4 million
and
$31.6 million
, respectively, of current restricted cash and
$8.9 million
and
$15.2 million
, respectively, of long-term restricted cash used to collateralize performance guarantees related to our petroleum contracts. As of June 30, 2018, we also had
$0.3 million
in other long-term restricted cash.
In addition, prior to our reserves based debt facility (the "Facility") being amended and restated in February 2018, we were required to maintain a restricted cash balance that was sufficient to meet the payment of interest and fees for the next
six
-month period on the
7.875%
Senior Secured Notes due 2021 (“Senior Notes”) plus the Corporate Revolver, or the Facility, whichever was greater. As of
December 31, 2017
, we had
$24.8 million
in current restricted cash to meet this requirement. Under the amended and restated Facility, we are no longer required to maintain a restricted cash balance provided we are compliant with certain financial covenant ratios.
Inventories
Inventories consisted of
$65.1 million
and
$63.5 million
of materials and supplies and
$6.0 million
and
$8.4 million
of hydrocarbons as of
June 30, 2018
and
December 31, 2017
, respectively. The Company’s materials and supplies inventory primarily consists of casing and wellheads and is stated at the lower of cost, using the weighted average cost method, or net realizable value.
Hydrocarbon inventory is carried at the lower of cost, using the weighted average cost method, or net realizable value. Hydrocarbon inventory costs include expenditures and other charges incurred in bringing the inventory to its existing condition. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory costs.
Revenue Recognition
We use the sales method of accounting for oil and gas revenues. Under this method, we recognize revenues on the volumes sold. The volumes sold may be more or less than the volumes to which we are entitled based on our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves on such property. As of
June 30, 2018
and
December 31, 2017
, we had no oil and gas imbalances recorded in our consolidated financial statements.
Our oil and gas revenues are recognized based on the product that has transferred to the customer during the lifting process as of a point in time when control has transferred, usually over a 24 hour period, and generally based on provisional price contracts which contain an embedded derivative that is required to be separated from the host contract for accounting purposes. The host contract is the receivable from oil sales at the spot price on the date of sale. The embedded derivative, which is not designated as a hedge, is marked to market through oil and gas revenue each period until the final settlement occurs, which generally is limited to the month after the sale.
Oil and gas revenue is composed of the following:
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
||||||||||||||
|
|
2018
|
2017
|
2018
|
2017
|
|||||||||||
|
|
(In thousands)
|
||||||||||||||
|
Revenue from contracts with customers - Ghana
|
$
|
213,841
|
|
$
|
140,915
|
|
$
|
341,878
|
|
$
|
244,355
|
|
|||
|
Provisional oil sales contracts
|
1,350
|
|
(4,552
|
)
|
509
|
|
(4,560
|
)
|
|||||||
|
Oil and gas revenue
|
$
|
215,191
|
|
$
|
136,363
|
|
342,387
|
|
239,795
|
|
|||||
12
Recent Accounting Standards
Recently Adopted
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2017 for public companies. Entities have the option of using either a full retrospective or modified retrospective approach to adopt ASU 2014-09. The Company adopted the new standard during the first quarter of 2018 using the modified retrospective approach and there is no impact to our previously recorded revenue under the new standard.
In March 2018, the FASB issued ASU 2018-05, “Income Taxes (Topic 740).” ASU 2018-05 was issued to include amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118") and addresses certain circumstances that may arise for registrants in accounting for the income tax effects of the Tax Cut and Jobs Act (the "Tax Reform Act"), including when certain income tax effects of the Tax Reform Act are incomplete by the time the financial statements are issued.
Not Yet Adopted
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 was issued to increase transparency and comparability across organizations by recognizing substantially all leases on the balance sheet through the concept of right-of-use lease assets and liabilities. Under current accounting guidance, lessees do not recognize lease assets or liabilities for leases classified as operating leases. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years with early adoption permitted. The new leasing standard requires the modified retrospective adoption method. The Company is in the process of evaluating its contract population to determine the impact of this accounting standard on its consolidated financial statements.
3. Acquisitions and Divestitures
2018 Transactions
In March 2018, as part of our alliance with BP, we entered into petroleum contracts covering Blocks 10 and 13 with the Democratic Republic of Sao Tome and Principe. We presently have a
35%
participating interest in the blocks and the operator, BP, holds a
50%
participating interest. The national petroleum agency, Agencia Nacional Do Petroleo De Sao Tome E Principe ("ANP STP") has a
15%
carried interest in the blocks through exploration. The petroleum contracts cover approximately
13,600
square kilometers, with a first exploration period of
four
years from the effective date (March 2018). The exploration period can be extended an additional
four
years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a
13,500
square kilometer 3D seismic acquisition requirement across the
two
blocks.
In June 2018, we closed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a
40%
non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contracts cover approximately
3,500
square kilometers, with a first exploration period of
three
years from the effective date (March 2018) which can be extended up to
four
additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a
3,000
square kilometer 3D seismic acquisition requirement.
In August 2018, we entered into an agreement to acquire Deep Gulf Energy (together with its subsidiaries "DGE"), a deepwater company operating in the Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of
$1.225 billion
, comprised of
$925 million
in cash and
$300 million
in Kosmos common stock, subject to post-closing adjustments. We intend to fund the cash portion of the purchase price with borrowings under our existing credit facilities. We also received
$200 million
of additional firm commitments under the Facility, which provides further liquidity to the Company. The acquisition is expected to close around the end of the third quarter 2018, subject to receipt of regulatory approval and the satisfaction of customary closing conditions.
13
2017 Transactions
In the fourth quarter of 2017, through a joint venture with an affiliate of Trident Energy ("Trident"), we acquired all of the equity interest of Hess International Petroleum Inc., a subsidiary of Hess Corporation ("Hess"), which held an
85%
paying interest (
80.75%
revenue interest) in the Ceiba Field and Okume Complex assets located in Block G offshore Equatorial Guinea. Under the terms of the agreement, Kosmos and Trident each own
50%
of Hess International Petroleum Inc, which was subsequently renamed Kosmos-Trident International Petroleum Inc. ("KTIPI"). Kosmos is primarily responsible for exploration and subsurface evaluation while Trident is primarily responsible for production operations and optimization. The gross acquisition price was
$650 million
effective as of
January 1, 2017
. After purchase price adjustments, Kosmos paid net cash consideration of approximately
$231 million
at close with a combination of cash on hand and amounts borrowed under the Facility. The transaction is accounted for as an equity method investment.
In October 2017, we entered into petroleum contracts covering Blocks EG-21, S, and W with the Republic of Equatorial Guinea. In May 2018, we signed a farm-out agreement with Trident, subject to final government approval, whereby they acquired a
40%
participating interest. After giving effect to the farm-out agreement, we hold a
40%
participating interest and are the operator in all
three
blocks. The Equatorial Guinean national oil company, Guinea Equatorial De Petroleos ("GEPetrol"), has a
20%
carried participating interest during the exploration period. Should a commercial discovery be made, GEPetrol's
20%
carried interest will convert to a
20%
participating interest. The petroleum contracts cover approximately
6,000
square kilometers, with a first exploration period of
five
years from the effective date (March 2018). The first exploration period consists of
two
sub-periods of
three
and
two
years, respectively. The first exploration sub-period work program includes a
6,000
square kilometer 3D seismic acquisition requirement across the
three
blocks.
In
December 2017
, as part of our alliance with BP, we entered into petroleum contracts covering Blocks CI-526, CI-602, CI-603, CI-707 and CI-708 with the Government of Cote d'Ivoire. We have a
45%
participating interest and are the operator in all
five
blocks. BP has a
45%
participating interest in the blocks and the Cote d'Ivoire national oil company, PETROCI Holding ("PETROCI"), currently has a
10%
carried interest. The petroleum contracts cover approximately
17,000
square kilometers, with a first exploration period of
three
years. The first exploration period work program includes a
12,000
square kilometer 3D seismic acquisition across the
five
blocks.
4. Joint Interest Billings
The Company’s joint interest billings consist of receivables from partners with interests in common oil and gas properties operated by the Company. Joint interest billings are classified on the face of the consolidated balance sheets as current and long-term receivables based on when collection is expected to occur.
In 2014, the Ghana National Petroleum Corporation (“GNPC”) notified us and our block partners of its request for the contractor group to pay GNPC’s
5%
share of the Tweneboa, Enyenra and Ntomme (“TEN”) development costs. The block partners will be reimbursed for such costs plus interest out of a portion of GNPC’s TEN production revenues. As of
June 30, 2018
and
December 31, 2017
, the current portion of the joint interest billing receivables due from GNPC for the TEN fields development costs were
$14.0 million
and
$15.2 million
, respectively, and the long-term portion were
$29.0 million
and
$31.6 million
, respectively.
14
5. Property and Equipment
Property and equipment is stated at cost and consisted of the following:
|
|
June 30,
2018 |
December 31,
2017 |
|||||
|
|
(In thousands)
|
||||||
|
Oil and gas properties:
|
|
|
|
|
|||
|
Proved properties
|
$
|
1,676,732
|
|
$
|
1,653,616
|
|
|
|
Unproved properties
|
492,468
|
|
465,109
|
|
|||
|
Support equipment and facilities
|
1,442,325
|
|
1,427,054
|
|
|||
|
Total oil and gas properties
|
3,611,525
|
|
3,545,779
|
|
|||
|
Accumulated depletion
|
(1,357,710
|
)
|
(1,234,806
|
)
|
|||
|
Oil and gas properties, net
|
2,253,815
|
|
|
2,310,973
|
|
||
|
Other property
|
43,906
|
|
39,405
|
|
|||
|
Accumulated depreciation
|
(34,657
|
)
|
(32,550
|
)
|
|||
|
Other property, net
|
9,249
|
|
6,855
|
|
|||
|
Property and equipment, net
|
$
|
2,263,064
|
|
$
|
2,317,828
|
|
|
We recorded depletion expense of
$71.3 million
and
$69.9 million
for the three months ended
June 30, 2018
and
2017
, respectively, and
$122.9 million
and
$102.4 million
for the
six months ended
June 30, 2018
and
2017
, respectively.
6. Suspended Well Costs
The following table reflects the Company’s capitalized exploratory well costs on completed wells as of and during the
six
months ended
June 30, 2018
. The table excludes
$43.8 million
in costs that were capitalized and subsequently expensed during the same period.
|
|
June 30,
2018 |
||
|
|
(In thousands)
|
||
|
Beginning balance
|
$
|
410,113
|
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
6,619
|
|
|
|
Reclassification due to determination of proved reserves
|
—
|
|
|
|
Capitalized exploratory well costs charged to expense
|
(796
|
)
|
|
|
Ending balance
|
$
|
415,936
|
|
15
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and the number of projects for which exploratory well costs have been capitalized for more than one year since the completion of drilling:
|
|
June 30, 2018
|
December 31, 2017
|
|||||
|
|
(In thousands, except well counts)
|
||||||
|
Exploratory well costs capitalized for a period of one year or less
|
$
|
35,513
|
|
$
|
67,159
|
|
|
|
Exploratory well costs capitalized for a period of one to two years
|
258,998
|
|
291,252
|
|
|||
|
Exploratory well costs capitalized for a period of three to six years
|
121,425
|
|
51,702
|
|
|||
|
Ending balance
|
$
|
415,936
|
|
$
|
410,113
|
|
|
|
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
|
5
|
|
5
|
|
|||
As of
June 30, 2018
, the projects with exploratory well costs capitalized for more than one year since the completion of drilling are related to the Akasa discovery in the West Cape Three Points (“WCTP”) Block and the Wawa discovery in the DT Block, which are all located offshore Ghana, the Greater Tortue discovery which crosses the Mauritania and Senegal maritime border, the BirAllah discovery (formerly known as the Marsouin discovery) in Block C8 offshore Mauritania and the Yakaar and Teranga discoveries in the Cayar Offshore Profond block offshore Senegal.
Akasa Discovery — We are currently in discussions with the government of Ghana regarding additional technical studies and evaluation that we want to conduct before we are able to make a determination regarding commerciality of the discovery. If we determine the discovery to be commercial, a declaration of commerciality would be provided and a PoD would be prepared and submitted to Ghana’s Ministry of Energy, as required under the WCTP petroleum contract. We expect that the Akasa discovery will be discussed in detail with the partnership group during our third quarter partner meetings in October 2018.
Wawa Discovery — We are currently in discussions with the Ministry of Energy with respect to conducting further subsurface and development concept evaluation in an effort to enlarge the TEN development and production area to capture the resource accumulation located in the Wawa Discovery Area for a potential future integrated development with the TEN fields. We expect that the Wawa discovery will be further discussed with the partnership group during our third quarter partner meetings in October 2018.
Greater Tortue Discovery — In May 2015, we completed the Tortue-1 exploration well in Block C8 offshore Mauritania, which encountered hydrocarbon pay.
Two
additional wells have been drilled in the Greater Tortue Discovery area, Ahmeyim-2 in Mauritania and Guembeul-1 in Senegal. We completed a drill stem test on the Tortue‑1 well in August 2017, which confirmed the production capabilities of the Greater Tortue Discovery. Data acquired from the drill stem test will be used to further optimize field development and to refine process design parameters critical to the Front End Engineering Design ("FEED") process. Following additional evaluation, a decision regarding commerciality will be made.
BirAllah Discovery — In November 2015, we completed the Marsouin-1 exploration well (renamed BirAllah) in the northern part of Block C8 offshore Mauritania which encountered hydrocarbon pay. Following additional evaluation, a decision regarding commerciality will be made.
Yakaar and Teranga Discoveries — In May 2016, we completed the Teranga-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In June 2017, we completed the Yakaar-1 exploration well in the Cayar Offshore Profond block offshore Senegal which encountered hydrocarbon pay. In November 2017, an integrated Yakaar-Teranga appraisal plan was submitted. Following additional evaluation, a decision regarding commerciality will be made.
7. Equity Method Investments
Kosmos BP Senegal Limited ("KBSL")
As part of our transaction in Senegal with BP in February 2017, our participating interests in the Cayar Offshore Profond and Saint Louis Offshore Profond blocks (the "Senegal Blocks") were contributed to KBSL, a corporate joint venture entity in which we owned a
50.01%
interest which was accounted for under the equity method of accounting.
16
In October 2017, KBSL transferred a
30%
participating interest in the Senegal Blocks to BP Senegal Investments Limited in exchange for its outstanding shares of KBSL. As a result, KBSL became a wholly-owned subsidiary of Kosmos, and no longer is accounted for under the equity method of accounting. After the transfer, KBSL has a
30%
participating interest in the Senegal Blocks.
During the
three and six
month periods ended
June 30,
2017 we recognized
$6.4 million
related to our share of losses in KBSL. Our initial contribution to KBSL was
$133.9 million
, which was recorded at our carrying costs.
Equatorial Guinea
As part of our acquisition of KTIPI, a corporate joint venture entity in which we own a
50%
interest, we acquired an indirect participating interest in Block G offshore Equatorial Guinea. The objective of this transaction was to acquire the Ceiba Field and Okume Complex with the intent to optimize production and increase reserves. Below is a summary of financial information for KTIPI presented on a
100%
basis.
|
|
June 30,
|
December 31,
|
|||||
|
|
2018
|
2017
|
|||||
|
|
(In thousands)
|
||||||
|
Assets
|
|
|
|||||
|
Total current assets
|
$
|
164,997
|
|
$
|
179,070
|
|
|
|
Property and equipment, net
|
311,138
|
|
345,611
|
|
|||
|
Other assets
|
544
|
|
567
|
|
|||
|
Total assets
|
$
|
476,679
|
|
$
|
525,248
|
|
|
|
Liabilities and shareholders' equity
|
|||||||
|
Total current liabilities
|
$
|
132,096
|
|
$
|
106,769
|
|
|
|
Total long-term liabilities
|
548,434
|
|
565,591
|
|
|||
|
Shareholders' equity:
|
|||||||
|
Total shareholders' equity
|
(203,851
|
)
|
(147,112
|
)
|
|||
|
Total liabilities and shareholders' equity
|
$
|
476,679
|
|
$
|
525,248
|
|
|
17
|
|
Three Months Ended June 30, 2018
|
Six Months Ended June 30, 2018
|
|||||
|
(In thousands)
|
|||||||
|
Revenues and other income:
|
|
|
|||||
|
Oil and gas revenue
|
$
|
138,395
|
|
$
|
384,749
|
|
|
|
Other income
|
(170
|
)
|
117
|
|
|||
|
Total revenues and other income
|
138,225
|
|
384,866
|
|
|||
|
Costs and expenses:
|
|
||||||
|
Oil and gas production
|
23,332
|
|
75,033
|
|
|||
|
Depletion and depreciation
|
21,881
|
|
75,951
|
|
|||
|
Other expenses, net
|
(73
|
)
|
(152
|
)
|
|||
|
Total costs and expenses
|
45,140
|
|
150,832
|
|
|||
|
Income before income taxes
|
93,085
|
|
234,034
|
|
|||
|
Income tax expense
|
33,620
|
|
83,251
|
|
|||
|
Net income
|
$
|
59,465
|
|
$
|
150,783
|
|
|
|
Kosmos' share of net income
|
$
|
29,733
|
|
$
|
75,392
|
|
|
|
Basis difference amortization(1)
|
13,633
|
|
40,596
|
|
|||
|
Equity in earnings - KTIPI
|
$
|
16,100
|
|
$
|
34,796
|
|
|
______________________________________
|
(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.
|
When evaluating our equity method investments for impairment, we review our ability to recover the carrying amount of such investments or the entity’s ability to sustain earnings that justify its carrying amount. As of
June 30, 2018
, we determined that we had the ability to recover the carrying amount of our equity method investment in KTIPI. As such,
no
impairment has been recorded. Our initial investment has been increased for our net share of equity in earnings as adjusted for our basis differential and reduced by cash dividends received. During the
six months ended
June 30, 2018
, we received
$120.0 million
of cash dividends from KTIPI, and we received an additional
$27.5 million
of cash dividends in July 2018.
|
|
June 30,
2018 |
December 31,
2017 |
|||||
|
|
(In thousands)
|
||||||
|
Outstanding debt principal balances:
|
|
|
|
|
|||
|
Facility
|
$
|
700,000
|
|
$
|
800,000
|
|
|
|
Senior Notes
|
525,000
|
|
525,000
|
|
|||
|
Total
|
1,225,000
|
|
1,325,000
|
|
|||
|
Unamortized deferred financing costs and discounts(1)
|
(57,225
|
)
|
(42,203
|
)
|
|||
|
Long-term debt, net
|
$
|
1,167,775
|
|
$
|
1,282,797
|
|
|
__________________________________
|
(1)
|
Includes
$40.9 million
and
$23.6 million
of unamortized deferred financing costs related to the Facility and
$16.3 million
and
$18.6 million
of unamortized deferred financing costs and discounts related to the Senior Notes as of
June 30, 2018
and
December 31, 2017
, respectively.
|
18
Facility
In February 2018, the Company amended and restated the Facility with a total commitment of
$1.5 billion
from a number of financial institutions with additional commitments up to
$0.5 billion
being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In August 2018, the Company entered into letter agreements with
two
existing financial institutions, which obligate the
two
financial institutions to provide the Company, upon the Company's election, with an additional commitment of
$200 million
in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and
$4.1 million
of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018. As of
June 30, 2018
, we have
$40.9 million
of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility.
As of
June 30, 2018
, borrowings under the Facility totaled
$700.0 million
and the undrawn availability under the Facility was
$800.0 million
.
During the second quarter of 2018, the Company voluntarily repaid
$100.0 million
of outstanding borrowings under the Facility, bringing the outstanding borrowings to
$700.0 million
. As of June 30, 2018, the borrowing availability was
$1.5 billion
.
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility, as amended in February 2018 expires
one month
prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of
June 30, 2018
, we had
no
letters of credit issued under the Facility.
We were in compliance with the financial covenants contained in the Facility as of
March 31, 2018
(the most recent assessment date). The Facility contains customary cross default provisions.
Corporate Revolver
In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at
$400.0 million
, extending the maturity date from November 2018 to May 2022 and lowering the margin
100
basis points to
5%
. This results in lower commitment fees on the undrawn portion of the total commitments which is
30%
per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs.
As of
June 30, 2018
, there were
no
outstanding borrowings under the Corporate Revolver. We were in compliance with the financial covenants contained in the Corporate Revolver as of
March 31, 2018
(the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
Revolving Letter of Credit Facility
We have a revolving letter of credit facility agreement (“LC Facility”), which matures in
July 2019
. In July 2018, the LC Facility size was voluntarily reduced to
$40.0 million
based on the maturation of several large outstanding letters of credit. As of
June 30, 2018
, there were
nine
outstanding letters of credit totaling
$36.9 million
under the LC Facility. The LC Facility contains customary cross default provisions.
7.875%
Senior Secured Notes due 2021
During August 2014, the Company issued
$300.0 million
of Senior Notes and received net proceeds of approximately
$292.5 million
after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
During April 2015, we issued an additional
$225.0 million
of Senior Notes and received net proceeds of
$206.8 million
after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional
$225.0 million
of Senior Notes have identical terms to the initial
$300.0 million
of Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
19
The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial
$300.0 million
Senior Notes and August 1, 2015 for the additional
$225.0 million
Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries.
At
June 30, 2018
, the estimated repayments of debt during the five fiscal year periods and thereafter are as follows:
|
|
Payments Due by Year
|
||||||||||||||||||||||||||
|
|
Total
|
2018(2)
|
2019
|
2020
|
2021
|
2022
|
Thereafter
|
||||||||||||||||||||
|
|
(In thousands)
|
||||||||||||||||||||||||||
|
Principal debt repayments(1)
|
$
|
1,225,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
525,000
|
|
|
$
|
—
|
|
|
$
|
700,000
|
|
__________________________________
|
(1)
|
Includes the scheduled principal maturities for the
$525.0 million
aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on, as of
June 30, 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. As of
June 30, 2018
, there were
no
borrowings under the Corporate Revolver.
|
|
(2)
|
Represents payments for the period
July 1, 2018
through
December 31, 2018
.
|
Interest and other financing costs, net
Interest and other financing costs, net incurred during the periods is comprised of the following:
|
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|||||||||||||
|
|
2018
|
2017
|
2018
|
2017
|
|||||||||||
|
|
(In thousands)
|
||||||||||||||
|
Interest expense
|
$
|
24,912
|
|
$
|
22,792
|
|
$
|
49,804
|
|
$
|
45,973
|
|
|||
|
Amortization—deferred financing costs
|
2,283
|
|
2,551
|
|
4,723
|
|
5,102
|
|
|||||||
|
Loss on extinguishment of debt
|
—
|
|
—
|
|
4,056
|
|
—
|
|
|||||||
|
Capitalized interest
|
(9,292
|
)
|
(7,376
|
)
|
(14,112
|
)
|
(16,935
|
)
|
|||||||
|
Deferred interest
|
166
|
|
634
|
|
(1,090
|
)
|
949
|
|
|||||||
|
Interest income
|
(843
|
)
|
(760
|
)
|
(1,791
|
)
|
(1,740
|
)
|
|||||||
|
Other, net
|
1,644
|
|
1,624
|
|
2,974
|
|
2,902
|
|
|||||||
|
Interest and other financing costs, net
|
$
|
18,870
|
|
$
|
19,465
|
|
$
|
44,564
|
|
$
|
36,251
|
|
|||
9. Derivative Financial Instruments
We use financial derivative contracts to manage exposures to commodity price and interest rate fluctuations. We do not hold or issue derivative financial instruments for trading purposes.
We manage market and counterparty credit risk in accordance with our policies and guidelines. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. We have included an estimate of non-performance risk in the fair value measurement of our derivative contracts as required by ASC 820 — Fair Value Measurements and Disclosures.
20
Oil Derivative Contracts
The following table sets forth the volumes in barrels underlying the Company’s outstanding oil derivative contracts and the weighted average Dated Brent prices per Bbl for those contracts as of
June 30, 2018
. Volumes and weighted average prices are net of any offsetting derivative contracts entered into.
|
|
|
|
|
|
|
Weighted Average Dated Brent Price per Bbl
|
|||||||||||||||||||||||
|
|
|
|
|
|
|
Net Deferred
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
|
|
|
|
|
|
Premium
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Term
|
|
Type of Contract
|
|
MBbl
|
|
Payable/(Receivable)
|
|
Swap
|
|
Sold Put
|
|
Floor
|
|
Ceiling
|
|
Call
|
|||||||||||||
|
2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
July — December
|
|
Swap with puts
|
|
3,000
|
|
|
$
|
—
|
|
|
$
|
56.75
|
|
|
$
|
43.33
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
July — December
|
Three-way collars
|
|
1,466
|
|
|
0.74
|
|
|
—
|
|
|
41.57
|
|
|
56.57
|
|
|
65.91
|
|
|
—
|
|
|||||||
|
July — December
|
Four-way collars
|
|
1,503
|
|
|
1.06
|
|
|
—
|
|
|
40.00
|
|
|
50.00
|
|
|
61.33
|
|
|
70.00
|
|
|||||||
|
July — December
|
Sold calls(1)
|
|
1,006
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65.00
|
|
|
—
|
|
|||||||
|
July — December
|
|
Purchased Calls
|
|
1,000
|
|
|
1.88
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
70.00
|
|
||||||
|
2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
|
January — December
|
Three-way collars
|
|
10,500
|
|
|
$
|
0.61
|
|
|
$
|
—
|
|
|
$
|
43.81
|
|
|
$
|
53.33
|
|
|
$
|
69.77
|
|
|
$
|
—
|
|
|
|
January — December
|
Sold calls(1)
|
|
913
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
80.00
|
|
|
—
|
|
|||||||
|
2020:
|
|||||||||||||||||||||||||||||
|
January — December
|
Sold calls(1)
|
4,000
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
80.00
|
|
$
|
—
|
|
||||||||
__________________________________
|
(1)
|
Represents call option contracts sold to counterparties to enhance other derivative positions.
|
In July 2018, we entered into call option contracts for
3.5
MMBbl from January 2019 through December 2019 with a purchased call price of
$65.00
per barrel and a sold call price of
$75.00
per barrel with a deferred premium payable of
$1.46
per barrel. In addition, we sold
3.5
MMBbl of calls from January 2020 through December 2020 with a strike price of
$80.00
per barrel and used the proceeds to increase the upside exposure on the 2019 calls. The contracts are indexed to Dated Brent prices.
Interest Rate Derivative Contracts
The following table summarizes our capped interest rate swaps whereby we pay a fixed rate of interest if LIBOR is below the cap, and pay the market rate less the spread between the cap (sold call) and the fixed rate of interest if LIBOR is above the cap as of
June 30, 2018
:
|
|
|
|
Weighted Average
|
|||||||||||
|
Term
|
Type of Contract
|
Floating Rate
|
Notional
|
Swap
|
Sold Call
|
|||||||||
|
|
|
|
(In thousands)
|
|
|
|||||||||
|
July 2018 — December 2018
|
Capped swap
|
1-month LIBOR
|
$
|
200,000
|
|
1.23
|
%
|
3.00
|
%
|
|||||
21
The following tables disclose the Company’s derivative instruments as of
June 30, 2018
and
December 31, 2017
and gain/(loss) from derivatives during the
three and six
months ended
June 30, 2018
and
2017
, respectively:
|
|
|
Estimated Fair Value
|
||||||||
|
|
|
Asset (Liability)
|
||||||||
|
Type of Contract
|
Balance Sheet Location
|
June 30,
2018 |
December 31,
2017 |
|||||||
|
|
|
(In thousands)
|
||||||||
|
Derivatives not designated as hedging instruments:
|
|
|
|
|||||||
|
Derivative assets:
|
|
|
|
|||||||
|
Commodity(1)
|
Derivatives assets—current
|
$
|
17,119
|
|
$
|
665
|
|
|||
|
Interest rate
|
Derivatives assets—current
|
934
|
|
1,017
|
|
|||||
|
Commodity(2)
|
Derivatives assets—long-term
|
10,421
|
|
39
|
|
|||||
|
Derivative liabilities:
|
|
|||||||||
|
Commodity(3)
|
Derivatives liabilities—current
|
(162,329
|
)
|
(67,531
|
)
|
|||||
|
Commodity(4)
|
Derivatives liabilities—long-term
|
(83,733
|
)
|
(30,209
|
)
|
|||||
|
Total derivatives not designated as hedging instruments
|
|
$
|
(217,588
|
)
|
$
|
(96,019
|
)
|
|||
__________________________________
|
(1)
|
Includes net deferred premiums payable of
$2.1 million
and net deferred premiums receivable of
$0.8 million
related to commodity derivative contracts as of
June 30, 2018
and
December 31, 2017
, respectively.
|
|
(2)
|
Includes net deferred premiums payable of
$0.9 million
and net deferred premiums receivable of
$0.1 million
related to commodity derivative contracts as of
June 30, 2018
and
December 31, 2017
, respectively.
|
|
(3)
|
Includes net deferred premiums payable of
$5.1 million
and
$5.6 million
related to commodity derivative contracts as of
June 30, 2018
and
December 31, 2017
, respectively.
|
|
(4)
|
Includes net deferred premiums payable of
$2.8 million
and
$4.8 million
related to commodity derivative contracts as of
June 30, 2018
and
December 31, 2017
, respectively.
|
|
|
|
Amount of Gain/(Loss)
|
Amount of Gain/(Loss)
|
|||||||||||||||
|
|
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
|
|
|
June 30,
|
June 30,
|
|||||||||||||||
|
Type of Contract
|
Location of Gain/(Loss)
|
2018
|
2017
|
2018
|
2017
|
|||||||||||||
|
|
|
(In thousands)
|
||||||||||||||||
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
|
|
|||||||||
|
Commodity(1)
|
Oil and gas revenue
|
$
|
1,350
|
|
$
|
(4,552
|
)
|
$
|
509
|
|
$
|
(4,560
|
)
|
|||||
|
Commodity
|
Derivatives, net
|
(140,272
|
)
|
25,411
|
|
(178,750
|
)
|
63,268
|
|
|||||||||
|
Interest rate
|
Interest expense
|
98
|
|
(92
|
)
|
451
|
|
236
|
|
|||||||||
|
Total derivatives not designated as hedging instruments
|
|
$
|
(138,824
|
)
|
$
|
20,767
|
|
$
|
(177,790
|
)
|
$
|
58,944
|
|
|||||
__________________________________
|
(1)
|
Amounts represent the change in fair value of our provisional oil sales contracts.
|
Offsetting of Derivative Assets and Derivative Liabilities
Our derivative instruments which are subject to master netting arrangements with our counterparties only have the right of offset when there is an event of default. As of
June 30, 2018
and
December 31, 2017
, there was not an event of default and, therefore, the associated gross asset or gross liability amounts related to these arrangements are presented on the consolidated balance sheets.
22
10. Fair Value Measurements
In accordance with ASC Topic 820 — Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. We prioritize the inputs used in measuring fair value into the following fair value hierarchy:
|
•
|
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.
|
The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of
June 30, 2018
and
December 31, 2017
, for each fair value hierarchy level:
|
|
Fair Value Measurements Using:
|
||||||||||||||
|
|
Quoted Prices in
|
|
|
|
|||||||||||
|
|
Active Markets for
|
Significant Other
|
Significant
|
|
|||||||||||
|
|
Identical Assets
|
Observable Inputs
|
Unobservable Inputs
|
|
|||||||||||
|
|
(Level 1)
|
(Level 2)
|
(Level 3)
|
Total
|
|||||||||||
|
|
(In thousands)
|
||||||||||||||
|
June 30, 2018
|
|
|
|
|
|
|
|
|
|||||||
|
Assets:
|
|
|
|
|
|
|
|
|
|||||||
|
Commodity derivatives
|
$
|
—
|
|
$
|
27,540
|
|
$
|
—
|
|
$
|
27,540
|
|
|||
|
Interest rate derivatives
|
—
|
|
934
|
|
—
|
|
934
|
|
|||||||
|
Liabilities:
|
|||||||||||||||
|
Commodity derivatives
|
—
|
|
(246,062
|
)
|
—
|
|
(246,062
|
)
|
|||||||
|
Total
|
$
|
—
|
|
$
|
(217,588
|
)
|
$
|
—
|
|
$
|
(217,588
|
)
|
|||
|
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
|
)
|
|||
The book values of cash and cash equivalents and restricted cash approximate fair value based on Level 1 inputs. Joint interest billings, oil sales and other receivables, and accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. Our long-term receivables, after any allowances for doubtful accounts, and other long-term assets approximate fair value. The estimates of fair value of these items are based on Level 2 inputs.
23
Commodity Derivatives
Our commodity derivatives represent crude oil collars, put options, call options and swaps for notional barrels of oil at fixed Dated Brent oil prices. The values attributable to our oil derivatives are based on (i) the contracted notional volumes, (ii) independent active futures price quotes for Dated Brent, (iii) a credit-adjusted yield curve applicable to each counterparty by reference to the credit default swap (“CDS”) market and (iv) an independently sourced estimate of volatility for Dated Brent. The volatility estimate was provided by certain independent brokers who are active in buying and selling oil options and was corroborated by market-quoted volatility factors. The deferred premium is included in the fair market value of the commodity derivatives. See Note 9 — Derivative Financial Instruments for additional information regarding the Company’s derivative instruments.
Provisional Oil Sales
The value attributable to provisional oil sales derivatives is based on (i) the sales volumes and (ii) the difference in the independent active futures price quotes for Dated Brent over the term of the pricing period designated in the sales contract and the spot price on the lifting date.
Interest Rate Derivatives
Our interest rate derivatives consist of interest rate swaps, whereby the Company pays a fixed rate of interest and the counterparty pays a variable LIBOR-based rate, and capped interest rate swaps, whereby the Company pays a fixed rate of interest if LIBOR is below the cap and pays the market rate less the spread between the cap and the fixed rate of interest if LIBOR is above the cap. The values attributable to the Company’s interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) LIBOR yield curves provided by independent third parties and corroborated with forward active market-quoted LIBOR yield curves and (iii) a credit-adjusted yield curve as applicable to each counterparty by reference to the CDS market.
Debt
The following table presents the carrying values and fair values at
June 30, 2018
and
December 31, 2017
:
|
|
June 30, 2018
|
December 31, 2017
|
|||||||||||||
|
|
Carrying Value
|
Fair Value
|
Carrying Value
|
Fair Value
|
|||||||||||
|
|
(In thousands)
|
||||||||||||||
|
Senior Notes
|
$
|
509,685
|
|
$
|
535,264
|
|
$
|
507,600
|
|
$
|
542,472
|
|
|||
|
Facility
|
700,000
|
|
700,000
|
|
800,000
|
|
800,000
|
|
|||||||
|
Total
|
$
|
1,209,685
|
|
$
|
1,235,264
|
|
$
|
1,307,600
|
|
$
|
1,342,472
|
|
|||
The carrying value of our Senior Notes represents the principal amounts outstanding less unamortized discounts. The fair value of our Senior Notes is based on quoted market prices, which results in a Level 1 fair value measurement. The carrying value of the Facility approximates fair value since it is subject to short-term floating interest rates that approximate the rates available to us for those periods.
11. Equity-based Compensation
Restricted Stock Awards and Restricted Stock Units
We record equity-based compensation expense equal to the fair value of share-based payments over the vesting periods of the Long Term Incentive Plan (“LTIP”) awards. We recorded compensation expense from awards granted under our LTIP of
$9.1 million
and
$10.5 million
during the three months ended
June 30, 2018
and
2017
, respectively, and
$17.1 million
and
$20.3 million
during the
six months ended
June 30, 2018
and
2017
, respectively. The total tax benefit for the three months ended
June 30, 2018
and
2017
was
$1.8 million
and
$3.5 million
, respectively, and
$3.4 million
and
$6.8 million
during the
six months ended
June 30, 2018
and
2017
, respectively. Additionally, we recorded a net tax shortfall (windfall) related to equity-based compensation of
$0.4 million
and
$3.0 million
for the three months ended
June 30, 2018
and
2017
, respectively, and
$(0.3) million
and
$2.8 million
during the
six months ended
June 30, 2018
and
2017
, respectively. The fair value of awards vested during the three months ended
June 30, 2018
and
2017
was approximately
$25.4 million
and
$10.5 million
, respectively, and
$82.0 million
and
$19.3 million
during the
six months ended
June 30, 2018
and
2017
, respectively. The Company granted both restricted stock awards and restricted stock units with service vesting criteria and granted both restricted stock awards and restricted stock units
24
with a combination of market and service vesting criteria under the LTIP. Substantially all these awards vest over
three
or
four
year periods. Restricted stock awards are issued and included in the number of outstanding shares upon the date of grant and, if such awards are forfeited, they become treasury stock. Upon vesting, restricted stock units become issued and outstanding stock.
The following table reflects the outstanding restricted stock awards as of
June 30, 2018
:
|
|
|
Weighted-
|
||||
|
|
Service Vesting
|
Average
|
||||
|
|
Restricted Stock
|
Grant-Date
|
||||
|
|
Awards
|
Fair Value
|
||||
|
|
(In thousands)
|
|
||||
|
Outstanding at December 31, 2017
|
220
|
|
$
|
8.64
|
|
|
|
Granted
|
—
|
|
—
|
|
||
|
Forfeited
|
—
|
|
—
|
|
||
|
Vested
|
(220
|
)
|
8.64
|
|
||
|
Outstanding at June 30, 2018
|
—
|
|
—
|
|
||
The following table reflects the outstanding restricted stock units as of
June 30, 2018
:
|
|
|
Weighted-
|
Market / Service
|
Weighted-
|
|||||||||
|
|
Service Vesting
|
Average
|
Vesting
|
Average
|
|||||||||
|
|
Restricted Stock
|
Grant-Date
|
Restricted Stock
|
Grant-Date
|
|||||||||
|
|
Units
|
Fair Value
|
Units
|
Fair Value
|
|||||||||
|
|
(In thousands)
|
|
(In thousands)
|
|
|||||||||
|
Outstanding at December 31, 2017
|
4,183
|
|
$
|
6.39
|
|
8,452
|
|
$
|
11.26
|
|
|||
|
Granted(1)
|
2,125
|
|
6.92
|
|
7,439
|
|
12.35
|
|
|||||
|
Forfeited
|
(63
|
)
|
6.73
|
|
(37
|
)
|
10.04
|
|
|||||
|
Vested
|
(2,062
|
)
|
6.93
|
|
(9,350
|
)
|
13.75
|
|
|||||
|
Outstanding at June 30, 2018
|
4,183
|
|
6.33
|
|
6,504
|
|
8.91
|
|
|||||
__________________________________
|
(1)
|
The restricted stock units with a combination of market and service vesting criteria include
4.9 million
shares granted as a result of the 2014 and 2015 awards achieving
200%
of their respective market performance conditions.
|
As of
June 30, 2018
, total equity-based compensation to be recognized on unvested restricted stock units is
$43.4 million
over a weighted average period of
2.24 years
. In January 2018, the board of directors approved an amendment to the plan to add
11.0 million
shares to the plan which was approved at the Annual General Meeting in June 2018. The LTIP provides for the issuance of
50.5 million
shares pursuant to awards under the plan. At
June 30, 2018
, the Company had approximately
16.0 million
shares that remain available for issuance under the LTIP.
For restricted stock units with a combination of market and service vesting criteria, the number of common shares to be issued is determined by comparing the Company’s total shareholder return with the total shareholder return of a predetermined group of peer companies over the performance period and can vest in up to
200%
of the awards granted. The grant date fair value ranged from
$4.83
to
$15.71
per award. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies and ranged from
44.0%
to
53.0%
. The risk-free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant and ranged from
0.7%
to
2.2%
.
25
12. Income Taxes
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax expense or benefit. The Company excludes zero tax rate and tax-exempt jurisdictions from our evaluation of the estimated annual effective income tax rate. The tax effect of discrete items are recognized in the period in which they occur at the applicable statutory tax rate.
On December 22, 2017, the President of the United States signed P.L. 115-97, the Tax Reform Act into law. SAB 118 was issued in January 2018 to address situations where certain aspects of the Jobs Act are unclear at issuance of a registrant’s financial statements for the reporting period in which the Jobs Act became law. SAB 118 allows us to record provisional amounts during a one-year measurement period. We are analyzing certain aspects of the Jobs Act which could affect the measurement of deferred tax balances or potentially give rise to new deferred tax amounts.
The income tax provision consists of United States and Ghanaian income and Texas margin taxes. Our operations in other foreign jurisdictions have a
0%
effective tax rate because they reside in countries with a
0%
statutory rate or we have incurred losses in those countries and have full valuation allowances against the corresponding net deferred tax assets.
Income (loss) before income taxes is composed of the following:
|
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|||||||||||||
|
|
2018
|
2017
|
2018
|
2017
|
|||||||||||
|
|
(In thousands)
|
||||||||||||||
|
Bermuda
|
$
|
(15,890
|
)
|
$
|
(16,759
|
)
|
$
|
(31,961
|
)
|
$
|
(32,940
|
)
|
|||
|
United States
|
1,682
|
|
1,382
|
|
3,315
|
|
2,794
|
|
|||||||
|
Foreign—other
|
(134,410
|
)
|
30,649
|
|
(194,546
|
)
|
38,754
|
|
|||||||
|
Income (loss) before income taxes
|
$
|
(148,618
|
)
|
$
|
15,272
|
|
$
|
(223,192
|
)
|
$
|
8,608
|
|
|||
Our effective tax rate for the
three months ended
June 30, 2018
and
2017
is
31%
and
155%
, respectively. For the
six months ended
,
June 30, 2018
and
2017
, our effective tax rate was
31%
and
533%
, respectively. For the periods ended June 30, 2018 and 2017 our overall effective tax rates were impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses.
The Company files income tax returns in all jurisdictions where such requirements exist, however, our primary tax jurisdictions are Ghana and the United States. The Company is open to Ghanaian federal income tax examinations for tax years 2014 through 2017 and in the United States, to federal income tax examinations for tax years 2014 through 2017.
As of
June 30, 2018
, the Company had
no
material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to income tax matters in income tax expense.
26
13.
Net Loss Per Share
The following table is a reconciliation between net
loss
and the amounts used to compute basic and diluted net
loss
per share and the weighted average shares outstanding used to compute basic and diluted net
loss
per share:
|
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||
|
|
June 30,
|
June 30,
|
|||||||||||||
|
|
2018
|
2017
|
2018
|
2017
|
|||||||||||
|
Numerator:
|
|
|
|
|
|
|
|
|
|||||||
|
Net loss
|
$
|
(103,273
|
)
|
$
|
(8,467
|
)
|
$
|
(153,499
|
)
|
$
|
(37,308
|
)
|
|||
|
Basic income allocable to participating securities(1)
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||
|
Basic net loss allocable to common shareholders
|
(103,273
|
)
|
(8,467
|
)
|
(153,499
|
)
|
(37,308
|
)
|
|||||||
|
Diluted adjustments to income allocable to participating securities(1)
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||
|
Diluted net loss allocable to common shareholders
|
$
|
(103,273
|
)
|
$
|
(8,467
|
)
|
$
|
(153,499
|
)
|
$
|
(37,308
|
)
|
|||
|
Denominator:
|
|||||||||||||||
|
Weighted average number of shares outstanding:
|
|||||||||||||||
|
Basic
|
396,826
|
|
387,952
|
|
396,218
|
|
387,634
|
|
|||||||
|
Restricted stock awards and units(1)(2)
|
—
|
|
—
|
|
—
|
|
—
|
|
|||||||
|
Diluted
|
396,826
|
|
387,952
|
|
396,218
|
|
387,634
|
|
|||||||
|
Net loss per share:
|
|||||||||||||||
|
Basic
|
$
|
(0.26
|
)
|
$
|
(0.02
|
)
|
$
|
(0.39
|
)
|
$
|
(0.10
|
)
|
|||
|
Diluted
|
$
|
(0.26
|
)
|
$
|
(0.02
|
)
|
$
|
(0.39
|
)
|
$
|
(0.10
|
)
|
|||
__________________________________
|
(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
loss
per common 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
loss
per common share calculation in periods we are in a net loss position.
|
|
(2)
|
We excluded outstanding restricted stock awards and units of
11.4 million
and
13.0 million
for the
three
months ended
June 30, 2018
and
2017
, respectively, and
11.9 million
and
13.0 million
for the
six
months ended
June 30, 2018
and
2017
, respectively, from the computations of diluted net
loss
per share because the effect would have been anti-dilutive
.
|
14. Commitments and Contingencies
From time to time, we are involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of our business in jurisdictions in which we do business. Although the outcome of these matters cannot be predicted with certainty, management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on our results from operations for a specific interim period or year.
We currently have a commitment to drill
one
exploration well in both Mauritania and Suriname.
In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea and Sao Tome and Principe, we have 3D seismic requirements of approximately
9,000
square kilometers and
13,500
square kilometers, respectively.
Future minimum rental commitments under our leases at
June 30, 2018
, are as follows:
|
|
Payments Due By Year(1)
|
||||||||||||||||||||||||||
|
|
Total
|
2018(2)
|
2019
|
2020
|
2021
|
2022
|
Thereafter
|
||||||||||||||||||||
|
|
(In thousands)
|
||||||||||||||||||||||||||
|
Operating leases(3)
|
$
|
11,930
|
|
|
$
|
2,521
|
|
|
$
|
5,251
|
|
|
$
|
1,366
|
|
|
$
|
419
|
|
|
$
|
419
|
|
|
$
|
1,954
|
|
__________________________________
|
(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.
|
27
|
(2)
|
Represents payments for the period from
July 1, 2018
through
December 31, 2018
.
|
|
(3)
|
Primarily relates to corporate office and foreign office leases.
|
15. Additional Financial Information
Accrued Liabilities
Accrued liabilities consisted of the following:
|
|
June 30,
2018 |
December 31,
2017 |
|||||
|
|
(In thousands)
|
||||||
|
Accrued liabilities:
|
|
|
|
|
|||
|
Exploration, development and production
|
$
|
85,079
|
|
$
|
144,717
|
|
|
|
General and administrative expenses
|
20,178
|
|
31,124
|
|
|||
|
Interest
|
20,331
|
|
20,457
|
|
|||
|
Income taxes
|
2,539
|
|
17,423
|
|
|||
|
Taxes other than income
|
3,906
|
|
3,270
|
|
|||
|
Derivatives
|
12,394
|
|
825
|
|
|||
|
Other
|
1,173
|
|
1,596
|
|
|||
|
|
$
|
145,600
|
|
$
|
219,412
|
|
|
Other Income, Net
Other income, net consisted of
zero
and
$10.2 million
of Loss of Production Income (“LOPI”) proceeds, net related to the turret bearing issue on the Jubilee FPSO for the three months ended
June 30, 2018
and
2017
, respectively and
zero
and
$58.7 million
for the
six
months ended
June 30, 2018
and
2017
, respectively. Our LOPI coverage for this incident ended in May 2017.
Oil and Gas Production
Oil and gas production expense included insurance recoveries related to our increased cost of working covered by our LOPI policy of
zero
and
$13.7 million
for the three months ended
June 30, 2018
and
2017
, respectively and
zero
and
$17.1 million
for the
six
months ended
June 30, 2018
and
2017
, respectively.
Facilities Insurance Modifications, Net
Facilities insurance modifications, net consists of costs associated with the long-term solution to convert the Jubilee FPSO to a permanently spread moored facility which we expect to recover from our insurance policy net of any insurance reimbursements.
Other Expenses, Net
Other expenses, net incurred during the period is comprised of the following:
|
|
Three Months Ended June 30,
|
Six Months Ended June 30,
|
|||||||||||||
|
|
2018
|
2017
|
2018
|
2017
|
|||||||||||
|
|
(In thousands)
|
||||||||||||||
|
(Gain) loss on disposal of inventory
|
$
|
(24
|
)
|
$
|
547
|
|
$
|
(24
|
)
|
$
|
547
|
|
|||
|
Gain on insurance settlements
|
—
|
|
—
|
|
—
|
|
(461
|
)
|
|||||||
|
Disputed charges and related costs
|
626
|
|
1,209
|
|
2,961
|
|
2,439
|
|
|||||||
|
Other, net
|
336
|
|
252
|
|
1,706
|
|
245
|
|
|||||||
|
Other expenses, net
|
$
|
938
|
|
$
|
2,008
|
|
$
|
4,643
|
|
$
|
2,770
|
|
|||
28
The disputed charges and related costs are expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow has charged such expenditures to the Deepwater Tano (“DT”) joint account. Kosmos disputed through arbitration that these expenditures were chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement.
In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we expect to recover from Tullow Ghana Limited the disputed charges, which include amounts previously paid under protest as well as certain costs and fees of pursuing the arbitration, estimated at approximately
$14 million
plus interest.
29
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and our annual financial statements for the year ended
December 31, 2017
, included in our annual report on Form 10-K along with the section Management’s Discussion and Analysis of financial condition and Results of Operations contained in such annual report. Any terms used but not defined in the following discussion have the same meaning given to them in the annual report. Our discussion and analysis includes forward-looking statements that involve risks and uncertainties and should be read in conjunction with “Risk Factors” under Item 1A of this report and in the annual report, along with “Forward-Looking Information” at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are
a pure play deepwater oil and gas company with growing production, a pipeline of development opportunities and a balanced exploration portfolio along the Atlantic Margins. Our assets include growing production offshore Ghana and Equatorial Guinea, a competitively positioned Tortue gas project in Mauritania and Senegal and a sustainable exploration program balanced between proven basins (Equatorial Guinea), emerging basins (Mauritania, Senegal and Suriname) and frontier basins (Cote d'Ivoire and Sao Tome and Principe).
Recent Developments
Deep Gulf Energy Acquisition
In August 2018, we entered into an agreement to acquire Deep Gulf Energy (together with its subsidiaries "DGE"), a deepwater company operating in the Gulf of Mexico, from First Reserve Corporation and other shareholders for a total consideration of
$1.225 billion
, comprised of
$925 million
in cash and
$300 million
in Kosmos common stock, subject to post-closing adjustments. We intend to fund the cash portion of the purchase price with borrowings under our existing credit facilities. We also received
$200 million
of additional firm commitments under the Facility, which provides further liquidity to the Company. The acquisition is expected to close around the end of the third quarter 2018, subject to receipt of regulatory approval and the satisfaction of customary closing conditions.
Corporate
In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at $400.0 million, extending the maturity date from November 2018 to May 2022 and lowering the margin 100 basis points to 5%. This results in lower commitment fees on the undrawn portion of the total commitments which is 30% per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs
Our revolving letter of credit facility agreement ("LC Facility") has flexibility that allows us to increase or decrease the available amount as needed if the existing lender increases its commitment or if commitments from new financial institutions are added. In July 2018, the LC Facility size was voluntarily reduced to
$40.0 million
based on the maturation of several large outstanding letters of credit.
Ghana
Jubilee
The Jubilee turret remediation work is progressing as planned as the second phase was completed during the second quarter of 2018. We expect rotation of the vessel to take place around the end of 2018 with minimal impact to production in 2018.
The financial impact of lower Jubilee production, as well as the additional expenditures associated with the damage to the turret bearing, is mitigated through a combination of the comprehensive Hull and Machinery insurance (“H&M”), procured by the operator, Tullow, on behalf of the Jubilee Unit partners, and through May 2017, the corporate Loss of Production Income (“LOPI”) insurance procured by Kosmos.
Tweneboa, Enyenra and Ntomme ("TEN")
The Ntomme-5 well is expected to be completed and brought online in early August 2018 and is expected to increase production towards FPSO capacity of 80,000 bopd.
30
Other
Kosmos and its partners have decided to add a second rig, the Stena Forth, in Ghana beginning in October 2018, which should allow drilling and completion operations to be accelerated. There will be no impact to the 2018 capital budget as the savings from the later arrival of the first rig will offset the costs of the second rig.
In June 2016, Kosmos Energy Ghana HC filed a Request for Arbitration with the International Chamber of Commerce against Tullow Ghana Limited in connection with a dispute arising under the DT Joint Operating Agreement. At dispute was Kosmos Energy Ghana HC’s responsibility for expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow sought to charge such expenditures to the DT joint account. Kosmos disputed that these expenditures were chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement and that the Seadrill West Leo drilling rig contract had not been entered into in connection with joint operations.
In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we expect to recover from Tullow Ghana Limited the disputed charges, which include amounts previously paid under protest as well as certain costs and fees of pursuing the arbitration, estimated at approximately
$14 million
plus interest.
Additionally, we are not required to fund a portion, estimated by Tullow to be approximately $50.8 million, of Tullow's liability to Seadrill.
Mauritania
In June 2018, we completed a 9,400 square kilometer survey over Block C18 offshore Mauritania.
Senegal
In July 2018, we entered into the second renewal of the exploration period for the Senegal Blocks Contract Areas, which lasts for two and one half years. In the event of commercial success, we have the right to develop and produce oil and/or gas for a period of 25 years from the grant of an exploitation authorization from the government, which may be extended for at least one additional period of 10 years under certain circumstances.
Equatorial Guinea
In June 2018, we closed a farm-in agreement with a subsidiary of Ophir Energy plc ("Ophir") for Block EG-24, offshore Equatorial Guinea, whereby we acquired a
40%
non-operated participating interest. As part of the agreement, we reimbursed a portion of Ophir's previously incurred exploration costs and will fully carry Ophir's share of the costs of a planned 3D seismic program as well as pay a disproportionate share of the well commitment should we enter the second exploration sub-period. The petroleum contracts cover approximately
3,500
square kilometers, with a first exploration period of
three
years from the effective date (March 2018) which can be extended up to
four
additional years at our election subject to fulfilling specific work obligations. The first exploration period work program includes a
3,000
square kilometer 3D seismic acquisition requirement.
In May 2018, we began a 3D seismic survey of approximately 10,100 square kilometers over blocks EG-21, EG-24, S and W offshore Equatorial Guinea, and approximately 200 square kilometers over Block G which is operated by our equity method investment in Kosmos-Trident International Petroleum Inc. ("KTIPI").
In May 2018, we signed a farm-out agreement with a subsidiary of Trident Energy (“Trident”), subject to final government approval, covering blocks S, W and EG21 offshore Equatorial Guinea. Under the terms of the agreement, Trident acquired a 40% non-operated participating interest in the blocks and Kosmos remains the operator.
Cote d'Ivoire
In May 2018, we completed a 3D seismic survey covering approximately 12,000 square kilometers over blocks CI-526, CI-602, CI-603, CI-707 and CI-708 offshore Cote d'Ivoire.
31
Suriname
In June 2018, the Anapai-1A exploration well was drilled to a total depth of approximately 4,600 meters and was designed to test lower Cretaceous reservoirs in a structural trap on the flank of the basin. The prospect was fully tested, encountering high quality reservoirs in the targeted zones, but did not find hydrocarbons. The well has been plugged and abandoned.
In July 2018, we entered into the second exploration phase in blocks 42 and 45. The second phase carries a one well commitment per block. This commitment has been met for Block 45 through the Anapai well and will be satisfied for Block 42 with the Pontoenoe exploration well which we plan to spud during the third quarter of 2018.
Results of Operations
All of our results, as presented in the table below, represent operations from Jubilee and TEN fields in Ghana and our equity method investment offshore Equatorial Guinea. Certain operating results and statistics for the
three and six
months ended
June 30, 2018
and
2017
are included in the following tables:
|
|
Three Months Ended
June 30, 2018 |
Six Months Ended
June 30, 2018 |
|||||||||||||||||||||
|
|
Kosmos
|
Equity Method Investment - Equatorial Guinea(1)
|
Total
|
Kosmos
|
Equity Method Investment Equatorial Guinea
|
Total
|
|||||||||||||||||
|
|
(In thousands, except per barrel data)
|
||||||||||||||||||||||
|
Sales volumes (MBbl):
|
|
|
|
||||||||||||||||||||
|
Jubilee
|
1,900
|
|
—
|
|
1,900
|
|
2,897
|
|
—
|
|
2,897
|
|
|||||||||||
|
TEN
|
995
|
|
—
|
|
995
|
|
1,932
|
|
—
|
|
1,932
|
|
|||||||||||
|
Ceiba / Okume
|
—
|
|
950
|
|
950
|
|
—
|
|
2,830
|
|
2,830
|
|
|||||||||||
|
2,895
|
|
950
|
|
3,845
|
|
4,829
|
|
2,830
|
|
7,659
|
|
||||||||||||
|
Revenues:
|
|
|
|
||||||||||||||||||||
|
Oil and gas sales
|
$
|
215,191
|
|
$
|
69,198
|
|
$
|
284,389
|
|
$
|
342,387
|
|
$
|
192,375
|
|
$
|
534,762
|
|
|||||
|
Average sales price per Boe
|
74.32
|
|
72.84
|
|
73.96
|
|
70.90
|
|
67.98
|
|
69.82
|
|
|||||||||||
|
|
|
||||||||||||||||||||||
|
Costs:
|
|
|
|
||||||||||||||||||||
|
Oil and gas production, excluding workovers
|
$
|
51,894
|
|
$
|
11,666
|
|
$
|
63,560
|
|
$
|
94,154
|
|
$
|
37,516
|
|
$
|
131,670
|
|
|||||
|
Oil and gas production, workovers
|
(2,079
|
)
|
—
|
|
(2,079
|
)
|
2,429
|
|
—
|
|
2,429
|
|
|||||||||||
|
Total oil and gas production costs
|
$
|
49,815
|
|
$
|
11,666
|
|
$
|
61,481
|
|
$
|
96,583
|
|
$
|
37,516
|
|
$
|
134,099
|
|
|||||
|
|
|
|
|
||||||||||||||||||||
|
Depletion and depreciation
|
$
|
74,289
|
|
$
|
24,574
|
|
$
|
98,863
|
|
$
|
128,566
|
|
$
|
78,572
|
|
$
|
207,138
|
|
|||||
|
|
|
||||||||||||||||||||||
|
Average cost per Boe:
|
|
|
|
||||||||||||||||||||
|
Oil and gas production, excluding workovers
|
$
|
17.93
|
|
$
|
12.28
|
|
$
|
16.53
|
|
$
|
19.51
|
|
$
|
13.26
|
|
$
|
17.19
|
|
|||||
|
Oil and gas production, workovers
|
(0.72
|
)
|
—
|
|
(0.54
|
)
|
0.50
|
|
—
|
|
0.32
|
|
|||||||||||
|
Total oil production costs
|
17.21
|
|
12.28
|
|
15.99
|
|
20.01
|
|
13.26
|
|
17.51
|
|
|||||||||||
|
|
|
||||||||||||||||||||||
|
Depletion and depreciation
|
25.66
|
|
25.87
|
|
25.71
|
|
26.61
|
|
27.76
|
|
27.05
|
|
|||||||||||
|
Oil and gas production cost and depletion costs
|
$
|
42.87
|
|
$
|
38.15
|
|
$
|
41.70
|
|
$
|
46.62
|
|
$
|
41.02
|
|
$
|
44.56
|
|
|||||
32
|
(1)
|
For the
three and six
months ended
June 30, 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, which is recorded in (gain) loss on equity method investments, net in the consolidated statement of operations.
|
|
|
Three Months Ended
June 30, 2017 |
Six Months Ended
June 30, 2017 |
|||||
|
|
(In thousands, except per barrel data)
|
||||||
|
Sales volumes (MBbl):
|
|
|
|||||
|
Jubilee
|
1,919
|
|
3,895
|
|
|||
|
TEN
|
996
|
|
996
|
|
|||
|
2,915
|
|
4,891
|
|
||||
|
Revenues:
|
|
|
|||||
|
Oil and gas sales
|
$
|
136,363
|
|
$
|
239,795
|
|
|
|
Average sales price per Boe
|
46.78
|
|
49.03
|
|
|||
|
Costs:
|
|
|
|||||
|
Oil and gas production, excluding workovers
|
$
|
21,045
|
|
$
|
40,992
|
|
|
|
Oil and gas production, workovers
|
559
|
|
498
|
|
|||
|
Total oil and gas production costs
|
$
|
21,604
|
|
$
|
41,490
|
|
|
|
Depletion and depreciation
|
$
|
72,441
|
|
$
|
107,419
|
|
|
|
Average cost per Boe:
|
|
|
|||||
|
Oil and gas production, excluding workovers
|
$
|
7.22
|
|
$
|
8.38
|
|
|
|
Oil and gas production, workovers
|
0.19
|
|
0.10
|
|
|||
|
Total oil production costs
|
7.41
|
|
8.48
|
|
|||
|
Depletion and depreciation
|
24.85
|
|
21.96
|
|
|||
|
Oil and gas production cost and depletion costs
|
$
|
32.26
|
|
$
|
30.44
|
|
|
33
The following table shows the number of wells in the process of being drilled or in active completion stages, and the number of wells suspended or waiting on completion as of
June 30, 2018
:
|
|
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
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
11
|
|
2.65
|
|
|||||||
|
West Cape Three Points
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
0.62
|
|
—
|
|
—
|
|
|||||||
|
TEN
|
—
|
|
—
|
|
1
|
|
0.17
|
|
—
|
|
—
|
|
5
|
|
0.85
|
|
|||||||
|
Deepwater Tano
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
0.18
|
|
—
|
|
—
|
|
|||||||
|
Mauritania
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
C8
|
—
|
|
—
|
|
—
|
|
—
|
|
3
|
|
0.84
|
|
—
|
|
—
|
|
|||||||
|
Senegal
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Saint Louis Offshore Profond
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
0.30
|
|
—
|
|
—
|
|
|||||||
|
Cayar Profond
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
0.60
|
|
—
|
|
—
|
|
|||||||
|
Total
|
—
|
|
—
|
|
1
|
|
0.17
|
|
9
|
|
2.54
|
|
16
|
|
3.50
|
|
|||||||
The discussion of the results of operations and the period-to-period comparisons presented below analyze our historical results. The following discussion may not be indicative of future results.
Three months ended
June 30, 2018
compared to three months ended
June 30, 2017
|
|
Three Months Ended
|
|
|||||||||
|
|
June 30,
|
Increase
|
|||||||||
|
|
2018
|
2017
|
(Decrease)
|
||||||||
|
|
(In thousands)
|
||||||||||
|
Revenues and other income:
|
|
|
|
|
|
|
|||||
|
Oil and gas revenue
|
$
|
215,191
|
|
$
|
136,363
|
|
$
|
78,828
|
|
||
|
Other income, net
|
282
|
|
10,161
|
|
(9,879
|
)
|
|||||
|
Total revenues and other income
|
215,473
|
|
146,524
|
|
68,949
|
|
|||||
|
Costs and expenses:
|
|
|
|
|
|
|
|||||
|
Oil and gas production
|
49,815
|
|
21,604
|
|
28,211
|
|
|||||
|
Facilities insurance modifications, net
|
1,029
|
|
(2
|
)
|
1,031
|
|
|||||
|
Exploration expenses
|
77,481
|
|
19,982
|
|
57,499
|
|
|||||
|
General and administrative
|
17,497
|
|
14,739
|
|
2,758
|
|
|||||
|
Depletion and depreciation
|
74,289
|
|
72,441
|
|
1,848
|
|
|||||
|
Interest and other financing costs, net
|
18,870
|
|
19,465
|
|
(595
|
)
|
|||||
|
Derivatives, net
|
140,272
|
|
(25,411
|
)
|
165,683
|
|
|||||
|
(Gain) loss on equity method investment, net
|
(16,100
|
)
|
6,426
|
|
(22,526
|
)
|
|||||
|
Other expenses, net
|
938
|
|
2,008
|
|
(1,070
|
)
|
|||||
|
Total costs and expenses
|
364,091
|
|
131,252
|
|
232,839
|
|
|||||
|
Income (loss) before income taxes
|
(148,618
|
)
|
15,272
|
|
(163,890
|
)
|
|||||
|
Income tax expense (benefit)
|
(45,345
|
)
|
23,739
|
|
(69,084
|
)
|
|||||
|
Net loss
|
$
|
(103,273
|
)
|
$
|
(8,467
|
)
|
$
|
(94,806
|
)
|
||
Oil and gas revenue.
Oil and gas revenue
increased
by
$78.8
million as a result of higher oil prices during the three months ended
June 30, 2018
, compared to the three months ended
June 30, 2017
. We lifted and sold
2,895
MBbl at an average
34
realized price per barrel of
$74.32
during the three months ended
June 30, 2018
and
2,915
MBbl at an average realized price per barrel of
$46.78
during the three months ended
June 30, 2017
.
Other income, net.
Other income, net
decreased
by
$9.9
million as we recognized $10.2 million of LOPI proceeds, net during the three months ended
June 30, 2017
related to the turret bearing issue on the Jubilee FPSO. The LOPI claim was finalized in June 2017.
Oil and gas production.
Oil and gas production costs
increased
by
$28.2
million during the three months ended
June 30, 2018
, as compared to the three months ended
June 30, 2017
. This is a result of insurance proceeds recognized related to Jubilee turret operating costs as well as credit accrual adjustments from the operator of the Jubilee and TEN fields operator during the three months ended June 30, 2017.
Facilities insurance modifications, net.
During the three months ended
June 30, 2018
, we incurred $9.4 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue. These costs were offset by $8.4 million of hull and machinery insurance proceeds received during the three months ended
June 30, 2018
resulting in a net charge of $1.0 million. During the three months ended
June 30, 2017
, we incurred $2.7 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue. These costs were offset by $2.7 million of hull and machinery insurance proceeds received during the three months ended
June 30, 2017
.
Exploration expenses.
Exploration expenses
increased
by
$57.5
million during the three months ended
June 30, 2018
, as compared to the three months ended
June 30, 2017
. The increase is primarily a result of $44.5 million of unsuccessful well costs for the Suriname Anapai-1 and 1A exploration wells and an increase in seismic and G&G costs for the three months ended
June 30, 2018
.
General and administrative.
General and administrative costs
increased
by
$2.8
million during the three months ended
June 30, 2018
, as compared with the three months ended
June 30, 2017
. The increase is driven by the loss of our ability to charge out certain costs associated with the transfer of operatorship of the Tortue development project and WCTP Block to BP and Tullow, respectively.
Depletion and depreciation.
Depletion and depreciation
increased
$1.8
million during the three months ended
June 30, 2018
, as compared with the three months ended
June 30, 2017
. The increase is primarily a result of a higher depletion rate for the Jubilee Field as a result of costs associated with the Mahogany and Teak discovery areas moving into the Jubilee Field's depletable cost basis in the fourth quarter of 2017.
Derivatives, net.
During the three months ended
June 30, 2018
and
2017
, we recorded a
loss
of
$140.3
million and a
gain
of
$25.4
million, respectively, on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods.
(Gain) loss on equity method investment, net
.
(Gain) loss on equity method investment, net
resulted in a
$22.5 million
positive impact compared to 2017 as a result of a $16.1 million gain on our equity method investment in KTIPI in 2018, compared to a $6.4 million loss recognized on our equity method investment in Kosmos BP Senegal Limited ("KBSL") in 2017.
Other expenses, net.
Other expenses, net
decreased
$1.1
million primarily related to a certain inventory write-offs and higher disputed charges and related costs in 2017.
Income tax expense (benefit).
For the
three months ended
June 30, 2018
, the Company recognized a net tax benefit because of pre-tax losses related to our Ghanaian operations. For the periods ended
June 30, 2018
and
2017
our overall effective tax rates were impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses.
35
Six months ended
June 30, 2018
compared to six months ended
June 30, 2017
|
|
Six Months Ended
|
|
|||||||||
|
|
June 30,
|
Increase
|
|||||||||
|
|
2018
|
2017
|
(Decrease)
|
||||||||
|
|
(In thousands)
|
||||||||||
|
Revenues and other income:
|
|
|
|
|
|
|
|||||
|
Oil and gas revenue
|
$
|
342,387
|
|
$
|
239,795
|
|
$
|
102,592
|
|
||
|
Other income, net
|
263
|
|
58,695
|
|
(58,432
|
)
|
|||||
|
Total revenues and other income
|
342,650
|
|
298,490
|
|
44,160
|
|
|||||
|
Costs and expenses:
|
|
|
|
|
|
|
|||||
|
Oil and gas production
|
96,583
|
|
41,490
|
|
55,093
|
|
|||||
|
Facilities insurance modifications, net
|
9,478
|
|
2,572
|
|
6,906
|
|
|||||
|
Exploration expenses
|
98,674
|
|
125,696
|
|
(27,022
|
)
|
|||||
|
General and administrative
|
39,380
|
|
30,526
|
|
8,854
|
|
|||||
|
Depletion and depreciation
|
128,566
|
|
107,419
|
|
21,147
|
|
|||||
|
Interest and other financing costs, net
|
44,564
|
|
36,251
|
|
8,313
|
|
|||||
|
Derivatives, net
|
178,750
|
|
(63,268
|
)
|
242,018
|
|
|||||
|
(Gain) loss on equity method investment, net
|
(34,796
|
)
|
6,426
|
|
(41,222
|
)
|
|||||
|
Other expenses, net
|
4,643
|
|
2,770
|
|
1,873
|
|
|||||
|
Total costs and expenses
|
565,842
|
|
289,882
|
|
275,960
|
|
|||||
|
Income (loss) before income taxes
|
(223,192
|
)
|
8,608
|
|
(231,800
|
)
|
|||||
|
Income tax expense (benefit)
|
(69,693
|
)
|
45,916
|
|
(115,609
|
)
|
|||||
|
Net loss
|
$
|
(153,499
|
)
|
$
|
(37,308
|
)
|
$
|
(116,191
|
)
|
||
Oil and gas revenue.
Oil and gas revenue
increased
by
$102.6 million
as a result of higher oil prices during the
six months ended
June 30, 2018
, compared to the
six months ended
June 30, 2017
. We lifted and sold
4,829
MBbl at an average realized price per barrel of
$70.90
during the
six months ended
June 30, 2018
and
4,891
MBbl at an average realized price per barrel of
$49.03
during the
six months ended
June 30, 2017
.
Other income, net.
Other income, net
decreased
by
$58.4 million
as we recognized $58.7 million of LOPI proceeds, net during the
six months ended
June 30, 2017
related to the turret bearing issue on the Jubilee FPSO. The LOPI claim was finalized in June 2017.
Oil and gas production.
Oil and gas production costs
increased
by
$55.1 million
during the
six months ended
June 30, 2018
, as compared to the
six months ended
June 30, 2017
primarily as a result of finalized LOPI claim insurance proceeds recognized related to increased costs due to turret issues as well as credit accrual adjustments from the operator of the Jubilee and TEN fields operator recognized during the
six months ended
June 30, 2017
.
Facilities insurance modifications, net.
During the
six months ended
June 30, 2018
, we incurred $19.2 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue. These costs were offset by $9.7 million of hull and machinery insurance proceeds received during the
six months ended
June 30, 2018
, resulting in a net charge of $9.5 million. During the
six months ended
June 30, 2017
, we incurred $10.2 million of facilities insurance modifications costs associated with the long-term solution to the Jubilee turret bearing issue. These costs were offset by $7.6 million of insurance proceeds received during the
six months ended
June 30, 2017
resulting in a net charge of $2.6 million.
Exploration expenses.
Exploration expenses
decreased
by
$27.0 million
during the
six months ended
June 30, 2018
, as compared to the
six months ended
June 30, 2017
. The change is primarily a result of $42.1 million of stacked rig costs associated with the ENSCO DS-12 (formerly the Atwood Achiever) and a $48.1 million cancellation payment related to the exercise of our election to cancel the fourth year option of the ENSCO DS-12 drilling rig contract, both recorded during the
six months ended
June 30, 2017
. These decreases were partially offset by $44.5 million of unsuccessful well costs for the Suriname Anapai-1 and 1A exploration wells and increases in seismic and geological and geophysical costs.
36
General and administrative.
General and administrative costs
increased
by
$8.9 million
during the
six months ended
June 30, 2018
, as compared with the
six months ended
June 30, 2017
. The increase is driven by the loss of our ability to charge out certain costs associated with the transfer of operatorship of the Tortue development project and WCTP Block to BP and Tullow, respectively.
Depletion and depreciation.
Depletion and depreciation
increased
$21.1 million
during the
six months ended
June 30, 2018
, as compared with the
six months ended
June 30, 2017
. The increase is primarily a result of a higher depletion rate for the TEN fields as 2018 had three Jubilee and two TEN liftings compared to four Jubilee and one TEN lifting in 2017. Additionally, the Jubilee Field depletion increased as a result of costs associated with the Mahogany and Teak discovery areas moving into the Jubilee Field's depletable cost basis in the fourth quarter of 2017.
Interest and other financing costs, net.
Interest and other financing costs, net
increased
$8.3 million
primarily a result of expensing $4.1 million of existing unamortized debt issuance costs and deferred interest in connection with amending the Facility in first quarter 2018 and a $4.2 million increase in interest related to a higher average interest rate and outstanding debt balance.
Derivatives, net.
During the
six months ended
June 30, 2018
and
2017
, we recorded a
loss
of
$178.8 million
and a
gain
of
$63.3 million
, respectively, on our outstanding hedge positions. The gain and loss recorded were a result of changes in the forward curve of oil prices during the respective periods.
(Gain) loss on equity method investment, net
.
(Gain) loss on equity method investment, net
resulted in a $34.8 million gain on our equity method investment in KTIPI in 2018, compared to a $6.4 million loss recognized on our equity method investment in KBSL in 2017.
Other expenses, net.
Other expenses, net
increased
$1.9 million
primarily related to an increase in disputed charges and related costs.
Income tax expense (benefit).
For the
six months ended
June 30, 2018
, the Company recognized a net tax benefit because of pre-tax losses related to our Ghanaian operations. For the periods ended
June 30, 2018
and
2017
our overall effective tax rates were impacted by non-deductible and non-taxable items associated with our U.S. and Ghanaian operations and other losses and expenses, primarily related to exploration operations in tax-exempt jurisdictions or in taxable jurisdictions where we have valuation allowances against our deferred tax assets, and therefore, we do not realize any tax benefit on such expenses or losses.
Liquidity and Capital Resources
We are actively engaged in an ongoing process of anticipating and meeting our funding requirements related to exploring for and developing oil and natural gas resources along the Atlantic Margins. We have historically met our funding requirements through cash flows generated from our operating activities and obtained additional funding from issuances of equity and debt as well as partner carries.
While we are presently in a strong financial position, commodity prices are volatile and could negatively impact our ability to generate sufficient operating cash flows to meet our funding requirements. To partially mitigate this price volatility, we maintain a hedging program. Our investment decisions are based on longer-term commodity prices based on the long-term nature of our projects and development plans. Also, BP has agreed to partially carry our exploration, appraisal and development program in Mauritania and Senegal. Current commodity prices, combined with our hedging program, partner carries and our current liquidity position support our capital program for 2018.
37
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the
six
months ended
June 30, 2018
and
2017
:
|
|
Six Months Ended
|
||||||
|
|
June 30,
|
||||||
|
|
2018
|
2017
|
|||||
|
|
(In thousands)
|
||||||
|
Sources of cash, cash equivalents and restricted cash:
|
|
|
|
|
|||
|
Net cash provided by (used in) operating activities
|
$
|
433
|
|
$
|
(17,514
|
)
|
|
|
Return of investment from KTIPI
|
79,970
|
|
—
|
|
|||
|
Proceeds on sale of assets
|
—
|
|
222,068
|
|
|||
|
|
80,403
|
|
204,554
|
|
|||
|
Uses of cash, cash equivalents and restricted cash:
|
|
|
|
|
|||
|
Oil and gas assets
|
92,650
|
|
42,805
|
|
|||
|
Other property
|
2,815
|
|
1,454
|
|
|||
|
Payments on long-term debt
|
100,000
|
|
200,000
|
|
|||
|
Purchase of treasury stock
|
17,695
|
|
1,945
|
|
|||
|
Deferred financing costs
|
25,743
|
|
—
|
|
|||
|
|
238,903
|
|
246,204
|
|
|||
|
Decrease in cash, cash equivalents and restricted cash
|
$
|
(158,500
|
)
|
$
|
(41,650
|
)
|
|
Net cash
provided by (used in)
operating activities.
Net cash
provided by
operating activities for the
six
months ended
June 30, 2018
was
$0.4
million compared with net cash
used in
operating activities for the
six
months ended
June 30, 2017
of
$17.5
million. The
increase
in cash
provided by
operating activities in the
six
months ended
June 30, 2018
when compared to the same period in
2017
is primarily a result of an increase in oil and gas revenue and a decrease in exploration expenses related to the stacked rig costs and rig option cancellation payment, both recorded during the
six
months ended
June 30, 2017
partially offset by a decrease in LOPI proceeds, net and an increase in payments related to derivative cash settlements.
The following table presents our net debt and liquidity as of
June 30, 2018
:
|
|
June 30, 2018
|
||
|
|
(In thousands)
|
||
|
Cash and cash equivalents
|
$
|
116,941
|
|
|
Restricted cash
|
29,545
|
|
|
|
Senior Notes at par
|
525,000
|
|
|
|
Drawings under the Facility
|
700,000
|
|
|
|
Net debt
|
$
|
1,078,514
|
|
|
|
|
|
|
|
Availability under the Facility
|
$
|
800,000
|
|
|
Availability under the Corporate Revolver
|
$
|
400,000
|
|
|
Available borrowings plus cash and cash equivalents
|
$
|
1,316,941
|
|
38
Capital Expenditures and Investments
We expect to incur capital costs as we:
|
•
|
drill additional wells in the Jubilee and TEN Fields;
|
|
•
|
fund asset integrity projects at Jubilee;
|
|
•
|
execute exploration and appraisal activities in a number of our exploration license areas, including drilling one exploration well in Suriname; and
|
|
•
|
acquire and analyze seismic on existing licenses, pursue new ventures and manage our rig activities.
|
We have relied on a number of assumptions in budgeting for our future activities. We also evaluate potential corporate and asset acquisition opportunities to support and expand our asset portfolio, which may impact our budget assumptions. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental and competitive uncertainties, contingencies and risks, all of which are difficult to predict and many of which are beyond our control. We may need to raise additional funds more quickly if market conditions deteriorate, or one or more of our assumptions proves to be incorrect or if we choose to expand our acquisition, exploration, appraisal, development efforts or any other activity more rapidly than we presently anticipate. We may decide to raise additional funds before we need them if the conditions for raising capital are favorable. We may seek to sell equity or debt securities or obtain additional bank credit facilities.
2018
Capital Program
We estimate we will spend approximately $300 million of capital, net of carry amounts related to the Mauritania and Senegal transactions with BP, for the year ending
December 31, 2018
. However, the ultimate amount of capital we will spend may vary or fluctuate materially based on market conditions and the success of our drilling results among other factors. Through
June 30, 2018
, we have spent approximately $154.8 million.
Significant Sources of Capital
Facility
In February 2018, the Company amended and restated the Facility with a total commitment of
$1.5 billion
from a number of financial institutions with additional commitments up to
$0.5 billion
being available if the existing financial institutions increase their commitments or if commitments from new financial institutions are added. In August 2018, the Company entered into letter agreements with
two
existing financial institutions, which obligate the
two
financial institutions to provide the Company, upon the Company's election, with an additional commitment of
$200 million
in the aggregate under the Facility. The borrowing base calculation includes value related to the Jubilee, TEN, Ceiba and Okume fields. The Facility supports our oil and gas exploration, appraisal and development programs and corporate activities. As part of the debt refinancing in February 2018, the repayment of borrowings under the existing facility attributable to financial institutions that did not participate in the amended Facility was accounted for as an extinguishment of debt, and
$4.1 million
of existing unamortized debt issuance costs and deferred interest attributable to those participants was expensed in interest and other financing costs, net in the first quarter of 2018. As of
June 30, 2018
, we have
$40.9 million
of unamortized issuance costs related to the Facility, which will be amortized over the remaining term of the Facility.
The Facility provides a revolving credit and letter of credit facility. The availability period for the revolving credit facility, as amended in February 2018 expires
one month
prior to the final maturity date. The letter of credit facility expires on the final maturity date. The available facility amount is subject to borrowing base constraints and, beginning on March 31, 2022, outstanding borrowings will be constrained by an amortization schedule. The Facility has a final maturity date of March 31, 2025. As of
June 30, 2018
, we had
no
letters of credit issued under the Facility.
We were in compliance with the financial covenants contained in the Facility as of
March 31, 2018
(the most recent assessment date). The Facility contains customary cross default provisions.
39
Corporate Revolver
In August 2018, we amended and restated the Corporate Revolver from a number of financial institutions, maintaining the borrowing capacity at
$400.0 million
, extending the maturity date from November 2018 to May 2022 and lowering the margin
100
basis points to
5%
. This results in lower commitment fees on the undrawn portion of the total commitments which is
30%
per annum of the respective margin. The Corporate Revolver is available for all subsidiaries for general corporate purposes and for oil and gas exploration, appraisal and development programs.
As of
June 30, 2018
, there were no outstanding borrowings under the Corporate Revolver. We were in compliance with the financial covenants contained in the Corporate Revolver as of
March 31, 2018
(the most recent assessment date). The Corporate Revolver contains customary cross default provisions.
Revolving Letter of Credit Facility
We have a revolving letter of credit facility agreement (“LC Facility”), which matures in
July 2019
. In July 2018, the LC Facility size was voluntarily reduced to
$40.0 million
based on the maturation of several large outstanding letters of credit. As of
June 30, 2018
, there were
nine
outstanding letters of credit totaling
$36.9 million
under the LC Facility. The LC Facility contains customary cross default provisions.
7.875% Senior Secured Notes due 2021
During August 2014, we issued $300.0 million of Senior Notes and received net proceeds of approximately $292.5 million after deducting discounts, commissions and deferred financing costs. The Company used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes.
During April 2015, we issued an additional $225.0 million Senior Notes and received net proceeds of $206.8 million after deducting discounts, commissions and other expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under the Facility and for general corporate purposes. The additional $225.0 million of Senior Notes have identical terms to the initial $300.0 million Senior Notes, other than the date of issue, the initial price, the first interest payment date and the first date from which interest accrued.
The Senior Notes mature on August 1, 2021. Interest is payable semi-annually in arrears each February 1 and August 1 commencing on February 1, 2015 for the initial $300.0 million Senior Notes and August 1, 2015 for the additional $225.0 million Senior Notes. The Senior Notes are secured (subject to certain exceptions and permitted liens) by a first ranking fixed equitable charge on all shares held by us in our direct subsidiary, Kosmos Energy Holdings. The Senior Notes are currently guaranteed on a subordinated, unsecured basis by our existing restricted subsidiaries that guarantee the Facility and the Corporate Revolver, and, in certain circumstances, the Senior Notes will become guaranteed by certain of our other existing or future restricted subsidiaries. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” section of our annual report on Form 10-K for the terms of the Senior Notes.
Contractual Obligations
The following table summarizes by period the payments due for our estimated contractual obligations as of
June 30, 2018
:
|
|
Payments Due By Year(4)
|
||||||||||||||||||||||||||
|
|
Total
|
2018(5)
|
2019
|
2020
|
2021
|
2022
|
Thereafter
|
||||||||||||||||||||
|
|
(In thousands)
|
||||||||||||||||||||||||||
|
Principal debt repayments(1)
|
$
|
1,225,000
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
525,000
|
|
$
|
—
|
|
$
|
700,000
|
|
||||||
|
Interest payments on long-term debt(2)
|
462,831
|
|
47,060
|
|
91,272
|
|
92,280
|
|
91,776
|
|
52,603
|
|
87,840
|
|
|||||||||||||
|
Operating leases(3)
|
11,930
|
|
2,521
|
|
5,251
|
|
1,366
|
|
419
|
|
419
|
|
1,954
|
|
|||||||||||||
__________________________________
|
(1)
|
Includes the scheduled principal maturities for the $525.0 million aggregate principal amount of Senior Notes issued in August 2014 and April 2015 and the Facility. The scheduled maturities of debt related to the Facility are based on the level of borrowings and the estimated future available borrowing base as of
June 30, 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.
|
40
|
(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 the 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.
|
|
(5)
|
Represents the period from
July 1, 2018
through
December 31, 2018
.
|
We currently have a commitment to drill
one
exploration well in both Mauritania and Suriname.
In Mauritania, our partner is obligated to fund our share of the cost of the exploration wells, subject to the remaining exploration and appraisal carry covering both our Mauritania and Senegal blocks. In Equatorial Guinea and Sao Tome and Principe, we have 3D seismic requirements of approximately
9,000
square kilometers and
13,500
square kilometers, respectively.
The following table presents maturities by expected debt maturity dates, the weighted average interest rates expected to be paid on the Facility given current contractual terms and market conditions, and the debt’s estimated fair value. Weighted-average interest rates are based on implied forward rates in the yield curve at the reporting date. This table does not take into account our Corporate Revolver, as there were no borrowings as of
June 30, 2018
, nor does it include amortization of deferred financing costs.
|
|
|
|
|
|
|
|
Asset
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
(Liability)
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
Fair Value at
|
||||||||||||||||||||
|
|
Years Ending December 31,
|
June 30,
|
|||||||||||||||||||||||||
|
|
2018(5)
|
2019
|
2020
|
2021
|
2022
|
Thereafter
|
2018
|
||||||||||||||||||||
|
|
(In thousands, except percentages)
|
||||||||||||||||||||||||||
|
Fixed rate debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Senior Notes
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
525,000
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(535,264
|
)
|
||||||
|
Fixed interest rate
|
7.88
|
%
|
7.88
|
%
|
7.88
|
%
|
7.88
|
%
|
—
|
|
—
|
|
|||||||||||||||
|
Variable rate debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Facility(1)
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
700,000
|
|
$
|
(700,000
|
)
|
||||||
|
Weighted average interest rate(2)
|
5.45
|
%
|
5.92
|
%
|
6.07
|
%
|
6.12
|
%
|
6.46
|
%
|
6.75
|
%
|
|
|
|||||||||||||
|
Capped interest rate swaps:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
|
Notional debt amount ($200,000)
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
934
|
|
||||||
|
Cap
|
3.00
|
%
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
|||||||||||||
|
Average fixed rate payable(3)
|
1.23
|
%
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
|||||||||||||
|
Variable rate receivable(4)
|
2.22
|
%
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
|||||||||||||
__________________________________
|
(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
June 30, 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. As of
June 30, 2018
, there were no borrowings under the Corporate Revolver.
|
|
(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.
|
|
(3)
|
We expect to pay the fixed rate if 1-month LIBOR is below the cap, and pay the market rate less the spread between the cap and the fixed rate if LIBOR is above the cap, net of the capped interest rate swaps.
|
|
(4)
|
Based on implied forward rates in the yield curve at the reporting date.
|
|
(5)
|
Represents the period
July 1, 2018
through
December 31, 2018
.
|
41
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of
June 30, 2018
, our material off-balance sheet arrangements and transactions include operating leases and undrawn letters of credit. There are no other transactions, arrangements, or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect Kosmos’ liquidity or availability of or requirements for capital resources.
Critical Accounting Policies
We consider accounting policies related to our revenue recognition, exploration and development costs, receivables, income taxes, derivative instruments and hedging activities, estimates of proved oil and natural gas reserves, asset retirement obligations and impairment of long-lived assets as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies which are summarized in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our annual report on Form 10-K, for the year ended
December 31, 2017
.
Cautionary Note Regarding Forward-looking Statements
This quarterly report on Form 10-Q contains estimates and forward-looking statements, principally in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Our estimates and forward-looking statements are mainly based on our current expectations and estimates of future events and trends, which affect or may affect our businesses and operations. Although we believe that these estimates and forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. Many important factors, in addition to the factors described in our quarterly report on Form 10-Q and our annual report on Form 10-K, may adversely affect our results as indicated in forward-looking statements. You should read this quarterly report on Form 10-Q, the annual report on Form 10-K and the documents that we have filed with the Securities and Exchange Commission completely and with the understanding that our actual future results may be materially different from what we expect. Our estimates and forward-looking statements may be influenced by the following factors, among others:
|
•
|
our ability to find, acquire or gain access to other discoveries and prospects and to successfully develop and produce from our current discoveries and prospects;
|
|
•
|
uncertainties inherent in making estimates of our oil and natural gas data;
|
|
•
|
the successful implementation of our and our block partners’ prospect discovery and development and drilling plans;
|
|
•
|
projected and targeted capital expenditures and other costs, commitments and revenues;
|
|
•
|
termination of or intervention in concessions, rights or authorizations granted 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, to us;
|
|
•
|
our dependence on our key management personnel and our ability to attract and retain qualified technical personnel;
|
|
•
|
the ability to obtain financing and to comply with the terms under which such financing may be available;
|
|
•
|
the volatility of oil and natural gas prices;
|
|
•
|
the availability, cost, function and reliability of developing appropriate infrastructure around and transportation to our discoveries and prospects;
|
|
•
|
the availability and cost of drilling rigs, production equipment, supplies, personnel and oilfield services;
|
|
•
|
other competitive pressures;
|
|
•
|
potential liabilities inherent in oil and natural gas operations, including drilling and production risks and other operational and environmental risks and hazards;
|
|
•
|
current and future government regulation of the oil and gas industry or regulation of the investment in or ability to do business with certain countries or regimes;
|
|
•
|
cost of compliance with laws and regulations;
|
|
•
|
changes in environmental, health and safety or climate change or greenhouse gas (“GHG”) laws and regulations or the implementation, or interpretation, of those laws and regulations;
|
|
•
|
adverse effects of sovereign boundary disputes in the jurisdictions in which we operate;
|
|
•
|
environmental liabilities;
|
|
•
|
geological, geophysical and other technical and operations problems, including drilling and oil and gas production and processing;
|
|
•
|
military operations, civil unrest, outbreaks of disease, terrorist acts, wars or embargoes;
|
|
•
|
the cost and availability of adequate insurance coverage and whether such coverage is enough to sufficiently mitigate potential losses and whether our insurers comply with their obligations under our coverage agreements;
|
42
|
•
|
our vulnerability to severe weather events;
|
|
•
|
our ability to meet our obligations under the agreements governing our indebtedness;
|
|
•
|
the availability and cost of financing and refinancing our indebtedness;
|
|
•
|
the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit and other secured debt;
|
|
•
|
the result of any legal proceedings, arbitrations, or investigations we may be subject to or involved in;
|
|
•
|
our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; and
|
|
•
|
other risk factors discussed in the “Item 1A. Risk Factors” section of this quarterly report on Form 10-Q and our annual report on Form 10-K.
|
The words “believe,” “may,” “will,” “aim,” “estimate,” “continue,” “anticipate,” “intend,” “expect,” “plan” and similar words are intended to identify estimates and forward-looking statements. Estimates and forward-looking statements speak only as of the date they were made, and, except to the extent required by law, we undertake no obligation to update or to review any estimate and/or forward-looking statement because of new information, future events or other factors. Estimates and forward-looking statements involve risks and uncertainties and are not guarantees of future performance. As a result of the risks and uncertainties described above, the estimates and forward-looking statements discussed in this quarterly report on Form 10-Q might not occur, and our future results and our performance may differ materially from those expressed in these forward-looking statements due to, including, but not limited to, the factors mentioned above. Because of these uncertainties, you should not place undue reliance on these forward-looking statements.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risks” as it relates to our currently anticipated transactions refers to the risk of loss arising from changes in commodity prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage ongoing market risk exposures. We enter into market-risk sensitive instruments for purposes other than to speculate.
We manage market and counterparty credit risk in accordance with our policies. In accordance with these policies and guidelines, our management determines the appropriate timing and extent of derivative transactions. See “Item 8. Financial Statements and Supplementary Data — Note 2 — Accounting Policies, Note 9 — Derivative Financial Instruments and Note 10 — Fair Value Measurements” section of our annual report on Form 10-K for a description of the accounting procedures we follow relative to our derivative financial instruments.
The following table reconciles the changes that occurred in fair values of our open derivative contracts during the
six
months ended
June 30, 2018
:
|
|
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
|
)
|
||
|
Changes in contract fair value
|
(178,241
|
)
|
451
|
|
(177,790
|
)
|
|||||
|
Contract maturities
|
56,755
|
|
(534
|
)
|
56,221
|
|
|||||
|
Fair value of contracts outstanding as of June 30, 2018
|
$
|
(218,522
|
)
|
$
|
934
|
|
$
|
(217,588
|
)
|
||
Commodity Price Risk
The Company’s revenues, earnings, cash flows, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, which have historically been very volatile. Our oil sales are indexed against Dated Brent crude; prices during the
six
months ended
June 30, 2018
ranged between $61.52 and $80.29.
Commodity Derivative Instruments
We enter into various oil derivative contracts to mitigate our exposure to commodity price risk associated with anticipated future oil production. These contracts currently consist of collars, put options, call options and swaps. In regards to our obligations
43
under our various commodity derivative instruments, if our production does not exceed our existing hedged positions, our exposure to our commodity derivative instruments would increase.
Commodity Price Sensitivity
The following table provides information about our oil derivative financial instruments that were sensitive to changes in oil prices as of
June 30, 2018
. Volumes and weighted average prices are net of any offsetting derivatives entered into.
|
|
|
|
Weighted Average Dated Brent Price per Bbl
|
Asset (Liability)
|
|||||||||||||||||||||||||||||
|
|
|
|
Net Deferred
|
|
|
|
|
|
Fair Value at
|
||||||||||||||||||||||||
|
|
|
|
Premium
|
|
|
|
|
|
June 30,
|
||||||||||||||||||||||||
|
Term
|
Type of Contract
|
MBbl
|
Payable/(Receivable)
|
Swap
|
Sold Put
|
Floor
|
Ceiling
|
Call
|
2018(2)
|
||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|||||||||||||||||||
|
2018:
|
|
|
|||||||||||||||||||||||||||||||
|
July — December
|
Swap with puts
|
3,000
|
|
$
|
—
|
|
$
|
56.75
|
|
$
|
43.33
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(60,845
|
)
|
|||||||||
|
July — December
|
Three-way collars
|
1,466
|
|
0.74
|
|
—
|
|
41.57
|
|
56.57
|
|
65.91
|
|
—
|
|
(19,443
|
)
|
||||||||||||||||
|
July — December
|
Four-way collars
|
1,503
|
|
1.06
|
|
—
|
|
40.00
|
|
50.00
|
|
61.33
|
|
70.00
|
|
(12,697
|
)
|
||||||||||||||||
|
July — December
|
Sold calls(1)
|
1,006
|
|
—
|
|
—
|
|
—
|
|
—
|
|
65.00
|
|
—
|
|
(12,854
|
)
|
||||||||||||||||
|
July — December
|
Purchased Calls
|
1,000
|
|
1.88
|
|
—
|
|
—
|
|
—
|
|
—
|
|
70.00
|
|
6,898
|
|
||||||||||||||||
|
2019:
|
|
|
|||||||||||||||||||||||||||||||
|
January — December
|
Three-way collars
|
10,500
|
|
$
|
0.61
|
|
$
|
—
|
|
$
|
43.81
|
|
$
|
53.33
|
|
$
|
69.77
|
|
$
|
—
|
|
$
|
(97,212
|
)
|
|||||||||
|
January — December
|
Sold calls(1)
|
913
|
|
—
|
|
—
|
|
—
|
|
—
|
|
80.00
|
|
—
|
|
(4,172
|
)
|
||||||||||||||||
|
2020:
|
|||||||||||||||||||||||||||||||||
|
January — December
|
Sold calls(1)
|
4,000
|
|
—
|
|
—
|
|
—
|
|
—
|
|
80.00
|
|
—
|
|
(18,197
|
)
|
||||||||||||||||
__________________________________
|
(1)
|
Represents call option contracts sold to counterparties to enhance other derivative positions.
|
|
(2)
|
Fair values are based on the average forward Dated Brent oil prices on
June 30, 2018
which by year are:
2018
— $78.01;
2019
— $74.05 and
2020
— $69.28. These fair values are subject to changes in the underlying commodity price. The average forward Dated Brent oil prices based on August 1, 2018 market quotes by year are:
2018
— $72.20;
2019
— $70.83 and
2020
— $67.87.
|
In July 2018, we entered into call option contracts for
3.5
MMBbl from January 2019 through December 2019 with a purchased call price of
$65.00
per barrel and a sold call price of
$75.00
per barrel with a deferred premium payable of
$1.46
per barrel. In addition, we sold
3.5
MMBbl of calls from January 2020 through December 2020 with a strike price of
$80.00
per barrel and used the proceeds to increase the upside exposure on the 2019 calls. The contracts are indexed to Dated Brent prices.
At
June 30, 2018
, our open commodity derivative instruments were in a net liability position of $218.5 million. As of
June 30, 2018
, a hypothetical 10% price increase in the commodity futures price curves would decrease future pre-tax earnings by approximately $101.7 million. Similarly, a hypothetical 10% price decrease would increase future pre-tax earnings by approximately $103.3 million.
Interest Rate Derivative Instruments
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations” section of our annual report on Form 10-K for specific information regarding the terms of our interest rate derivative instruments that are sensitive to changes in interest rates.
44
Interest Rate Sensitivity
At
June 30, 2018
, we had indebtedness outstanding under the Facility of
$700.0 million
, of which $500.0 million bore interest at floating rates after consideration of our fixed rate interest rate hedges. The interest rate on this indebtedness as of
June 30, 2018
was approximately 5.2%. If LIBOR increased by 10% at this level of floating rate debt, we would pay an additional $1.0 million in interest expense per year on the Facility. We pay commitment fees on the undrawn availability and unavailable commitments under the Facility and on the undrawn availability under the Corporate Revolver, which are not subject to changes in interest rates.
As of
June 30, 2018
, the fair market value of our interest rate swaps was a net asset of approximately $0.9 million. If LIBOR changed by 10%, it would have a negligible impact on the fair market value of our interest rate swaps.
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) was performed under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. However, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based upon this evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of
June 30, 2018
, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, including that such information is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure.
Evaluation of Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
45
There have been no material changes from the information concerning legal proceedings discussed in the “Item 3. Legal Proceedings” section of our annual report on Form 10-K.
In June 2016, Kosmos Energy Ghana HC filed a Request for Arbitration with the International Chamber of Commerce against Tullow Ghana Limited in connection with a dispute arising under the DT Joint Operating Agreement. At dispute was Kosmos Energy Ghana HC’s responsibility for expenditures arising from Tullow Ghana Limited’s contract with Seadrill for use of the West Leo drilling rig once partner-approved 2016 work program objectives were concluded. Tullow sought to charge such expenditures to the DT joint account. Kosmos disputed that these expenditures were chargeable to the DT joint account on the basis that the Seadrill West Leo drilling rig contract was not approved by the DT operating committee pursuant to the DT Joint Operating Agreement and that the Seadrill West Leo drilling rig contract had not been entered into in connection with joint operations.
In July 2018, the International Chamber of Commerce ("ICC") issued its Final Award in the arbitration in favor of Kosmos. As a result, we expect to recover from Tullow Ghana Limited the disputed charges, which include amounts previously paid under protest as well as certain costs and fees of pursuing the arbitration, estimated at approximately
$14 million
plus interest.
There have been no material changes from the risks discussed in the “Item 1A. Risk Factors” section of our annual report on Form 10-K for the year ended
December 31, 2017
.
Issuer Purchases of Equity Securities
Under the terms of our Long Term Incentive Plan (“LTIP”), we have issued restricted shares to our employees. On the date that these restricted shares vest, we provide such employees the option to sell shares to cover their tax liability, via a net exercise provision pursuant to our applicable restricted share award agreements and the LTIP, at either the number of vested shares (based on the closing price of our common shares on such vesting date) equal to the minimum statutorily tax liability owed by such grantee or up to the maximum statutory tax liability for such grantee. The Company may repurchase the restricted shares sold by the grantees to settle their tax liability. The repurchased shares are reallocated to the number of shares available for issuance under the LTIP. The following table outlines the total number of shares purchased during the
six
months ended
June 30, 2018
and the average price paid per share.
|
|
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
|
—
|
|
—
|
|
||
|
Total
|
74
|
|
6.85
|
|
||
|
Item 3.
|
Defaults Upon Senior Securities
|
None.
|
Item 4.
|
Mine Safety Disclosures
|
Not applicable.
46
|
Item 5.
|
Other Information.
|
There have been no material changes required to be reported under this Item that have not previously been disclosed in the annual report on Form 10-K.
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this quarterly report on Form 10‑Q.
47
SIGNATURES
Pursuant to the requirements of the Securities Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
Kosmos Energy Ltd.
|
|
|
|
|
(Registrant)
|
|
|
|
|
|
|
|
Date
|
August 6, 2018
|
|
/s/ THOMAS P. CHAMBERS
|
|
|
|
Thomas P. Chambers
|
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
|
|
(Principal Financial Officer)
|
|
48
INDEX OF EXHIBITS
|
Exhibit
Number
|
|
Description of Document
|
|
|
||
|
|
|
|
|
|
||
|
|
|
|
|
|
||
|
|
|
|
|
|
||
|
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
|
__________________________________
* Filed herewith.
** Furnished herewith.
49
TABLE OF CONTENTS
Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 3. Qualitative and Quantitative Disclosures About Market RiskItem 4. Controls and ProceduresPart II. Other InformationItem 1. Legal ProceedingsItem 1A. Risk FactorsItem 2. Unregistered Sales Of Equity Securities and Use Of ProceedsItem 3. Defaults Upon Senior SecuritiesItem 4. Mine Safety DisclosuresItem 5. Other InformationItem 6. Exhibits