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ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
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Delaware
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45-4502447
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(State or Other Jurisdiction of
Incorporation or Organization)
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(IRS Employer
Identification Number)
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500 West Texas, Suite 1200
Midland, Texas
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79701
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(Address of Principal Executive Offices)
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(Zip Code)
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Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, par value $0.01 per share
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The NASDAQ Stock Market LLC
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Securities registered pursuant to Section 12(g) of the Act: None
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Large Accelerated Filer
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ý
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Accelerated Filer
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Non-Accelerated Filer
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¨
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Smaller Reporting Company
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¨
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Page
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PART I
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PART II
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PART III
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PART IV
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Index to Consolidated Financial Statements
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3-D seismic
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Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
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Basin
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A large depression on the earth’s surface in which sediments accumulate.
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Bbl
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Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
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Bbls/d
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Barrels per day.
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BOE
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Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
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BOE/d
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Barrels of oil equivalent per day.
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Brent
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Brent sweet light crude oil.
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British Thermal Unit or BTU
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The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
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Completion
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The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
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Condensate
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Liquid hydrocarbons associated with the production that is primarily natural gas.
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Crude oil
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Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
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Developed acreage
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Acreage assignable to productive wells.
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Development costs
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Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves.
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Differential
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An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
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Dry hole or dry well
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A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
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Estimated Ultimate Recovery or EUR
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Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
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Exploitation
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A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
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Field
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An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
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Finding and development costs
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Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
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Fracturing
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The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
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Gross acres or gross wells
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The total acres or wells, as the case may be, in which a working interest is owned.
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Horizontal drilling
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A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
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Horizontal wells
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Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
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MBbls
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Thousand barrels of crude oil or other liquid hydrocarbons.
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MBOE
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One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
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Mcf
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Thousand cubic feet of natural gas.
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Mcf/d
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Thousand cubic feet per day.
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Mineral interests
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The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
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MMBtu
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Million British Thermal Units.
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MMcf
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Million cubic feet of natural gas.
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Net acres or net wells
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The sum of the fractional working interest owned in gross acres.
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Net revenue interest
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An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
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Oil and natural gas properties
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Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
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Operator
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The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
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Play
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A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
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Plugging and abandonment
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Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
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PUD
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Proved undeveloped.
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Productive well
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A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
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Prospect
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A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
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Proved developed reserves
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Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
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Proved reserves
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The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
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Proved undeveloped reserves
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Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
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Recompletion
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The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
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Reserves
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Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
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Reservoir
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A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
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Resource play
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A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
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Royalty interest
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An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations.
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Spacing
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The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
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Stratigraphic play
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An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.
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Structural play
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An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.
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Tight formation
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A formation with low permeability that produces natural gas with very low flow rates for long periods of time.
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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 economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
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Working interest
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An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
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WTI
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West Texas Intermediate.
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2012 Plan
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The Company’s 2012 Equity Incentive Plan.
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Bison
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Bison Drilling and Field Services, LLC.
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Company
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Diamondback Energy, Inc., a Delaware corporation, together with its subsidiaries.
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EPA
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U.S. Environmental Protection Agency.
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Exchange Act
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The Securities Exchange Act of 1934, as amended.
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FERC
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Federal Energy Regulatory Commission.
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GAAP
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Accounting principles generally accepted in the United States.
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General Partner
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Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
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Indenture
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The indenture relating to the Senior Notes, dated as of September 18, 2013, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
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Muskie
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Muskie Proppant LLC.
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NYMEX
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New York Mercantile Exchange.
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OSHA
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Federal Occupational Safety and Health Act.
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Partnership
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Viper Energy Partners LP, a Delaware limited partnership.
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Partnership agreement
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The first amended and restated agreement of limited partnership, dated as of June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the Viper Offering.
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Ryder Scott
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Ryder Scott Company, L.P.
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SEC
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Securities and Exchange Commission.
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Securities Act
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The Securities Act of 1933, as amended.
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Senior Notes
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The Company’s 7.625% senior unsecured notes due 2021 in the aggregate principal amount of $450 million.
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Viper
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Viper Energy Partners L.P.
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Viper LTIP
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Viper Energy Partners L.P. Long Term Incentive Plan.
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Viper Offering
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The Partnerships’ initial public offering.
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Wells Fargo
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Wells Fargo Bank, National Association.
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•
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business strategy;
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exploration and development drilling prospects, inventories, projects and programs;
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oil and natural gas reserves;
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acquisitions
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identified drilling locations;
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ability to obtain permits and governmental approvals;
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technology;
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financial strategy;
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realized oil and natural gas prices;
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production;
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lease operating expenses, general and administrative costs and finding and development costs;
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•
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future operating results; and
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plans, objectives, expectations and intentions.
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Grow production and reserves by developing our oil-rich resource base.
We intend to drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital.
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Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density.
We have targeted various intervals in the Wolfberry play through horizontal drilling and believe that there are opportunities to target additional intervals in the Wolfberry play with horizontal wells. Our initial horizontal focus had been on the Wolfcamp B interval
,
but our recent focus has primarily been on the Lower Spraberry interval. We have also begun to derisk the Wolfcamp A and Middle Spraberry on some of our properties.
Our first
two
horizontal wells were completed in
2012
and had lateral lengths of less than
4,000
feet. As of
December 31, 2015
, we had drilled
188
horizontal wells as operator and had participated in
25
additional horizontal wells as a non-operator, including
two
in which we own only a minor wellbore interest. We also acquired interest in
11
horizontal wells on properties we purchased. Of these
224
total horizontal wells,
184
had been completed and were on production. Of the
184
horizontal wells on production,
112
are in the Wolfcamp B interval,
23
are in the Clearfork zone,
58
are in the Spraberry zone, and
three
are in the Cline zone. These wells have lateral lengths ranging from approximately
4,000
feet to
11,000
feet. In
2016
, we expect that our average lateral lengths will be in the range of
7,000
feet to
8,000
feet, although the actual length will vary depending on the layout of our acreage and other factors. As technology improves, we expect that our average lateral lengths will increase, resulting in higher per well recoveries and lower development costs per BOE. During the year ended
December 31, 2015
, we were able to drill our horizontal wells with approximately
7,500
foot lateral lengths to total depth, or TD, in an average of
13.9
days and we drilled an approximately
10,000
foot lateral well in
14.2
days. Further advances in drilling and completion technology may result in economic development of zones that are not currently viable.
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Leverage our experience operating in the Permian Basin.
Our executive team, which has an average of over 25 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. Our focus on efficient drilling and completion techniques is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. We believe that the experience of our executive team in deviated and horizontal drilling and completions has helped reduce the execution risk normally associated with these complex well paths. In addition, our completion techniques are continually evolving as we evaluate and implement hydraulic fracturing practices that have and are expected to continue to increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.
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Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies.
Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately
96%
of our acreage. This operational control allows us to manage more efficiently the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average
80%
working interest in our acreage allows us to realize the majority of the benefits of these activities and cost efficiencies.
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Pursue strategic acquisitions with substantial resource potential.
We have a proven history of acquiring leasehold positions in the Permian Basin that have substantial oil-weighted resource potential. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We regularly review acquisition opportunities and intend to pursue acquisitions that meet our strategic and financial targets. During the year ended
December 31, 2015
, we acquired approximately
16,941
gross (
12,672
net) leasehold acres primarily in Howard, Martin, Andrews and Midland counties. We intend to continue to pursue acquisitions that meet our strategic and financial targets.
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Maintain financial flexibility.
We seek to maintain a conservative financial position. In connection with our fall 2015 redetermination, the agent lender under our revolving credit agreement recommended a borrowing base of
$750.0 million
. We elected a commitment amount of
$500.0 million
, of which
$489.0 million
was available for
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Oil rich resource base in one of North America’s leading resource plays.
All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. The majority of our current properties are well positioned in the core of the Wolfberry play. Our production for the year ended
December 31, 2015
was approximately
75%
oil,
14%
natural gas liquids and
11%
natural gas. As of
December 31, 2015
, our estimated net proved reserves were comprised of approximately
67%
oil and
17%
natural gas liquids.
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Multi-year drilling inventory in one of North America’s leading oil resource plays.
We have identified a multi-year inventory of potential drilling locations for our oil-weighted reserves that we believe provides attractive growth and return opportunities. At an assumed price of approximately
$40.00
per Bbl WTI, we currently have approximately
1,500
gross (
960
net) identified economic potential horizontal drilling locations on our acreage based on our our evaluation of applicable geologic and engineering data. These gross identified economic potential horizontal locations have an average lateral length of approximately
8,375
feet, with the actual length depending on lease geometry and other considerations. These locations exist across most of our acreage blocks and in multiple horizons. Of these
1,500
locations,
840
are in the Wolfcamp B horizon or the Lower Spraberry horizon, with the remaining locations in either the Wolfcamp A, Middle Spraberry, Clearfork, Wolfcamp C or Cline horizons. Our current horizontal location count for the Wolfcamp B horizon is based on 660 foot spacing between wells in all counties except Andrews, Dawson, Upton, and northwest Martin counties where it is 880 foot spacing. For the Lower Spraberry horizon, the horizontal location count is based on 500 foot spacing in the Spanish Trail property in Midland County and 660 foot spacing in other counties except Upton, Dawson and central Andrews counties where it is based on 880 foot spacing. In the Wolfcamp A horizon, the horizontal location count in based on 660 foot spacing in Howard and Glasscock counties, 880 foot spacing in Midland and southwest Martin counties and 1,320 foot spacing in other counties. Middle Spraberry counts are based on 880 foot spacing in Midland, Martin and northeast Andrews counties and 1,320 foot spacing in other counties. The horizontal location counts for the Cline, Clearfork and Wolfcamp C horizons are based on 1,320 spacing except for the Clearfork in central Andrews County which is based on 660 foot spacing. The ultimate inter-well spacing may vary from these distances due to different factors, which would result in a higher or lower location count. The two-stream gross estimated ultimate recoveries, or EURs, from our future PUD horizontal wells, as estimated by Ryder Scott as of
December 31, 2015
, range from
392
MBOE per well, consisting of
280
MBbls of oil and
673
MMcf of natural gas, to
1,318
MBOE per well, consisting of
1,035
MBbls of oil and
1,698
MMcf of natural gas, for wells ranging in lateral length from approximately
5,000
feet to approximately
10,000
feet, in intervals including the Clearfork, Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B. Ryder Scott has estimated gross EURs of
635
MBOE for our Wolfcamp B wells in Midland County and
990
MBOE for our Lower Spraberry wells in Midland County, which constitute
54%
of our remaining PUD horizontal wells, in each case based on
7,500
foot lateral lengths. In addition, we have approximately
698
square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including additional horizontal drilling opportunities and strategic leasehold acquisitions.
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Experienced, incentivized and proven management team.
Our executive team has an average of over 25 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which is of strategic importance as we expand our horizontal drilling activity. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.
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Favorable operating environment.
We have focused our drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. We believe that the geological and regulatory environment of the Permian Basin is more stable and predictable, and that we are faced with less operational risks, in the Permian Basin as compared to emerging hydrocarbon basins.
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•
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High degree of operational control.
We are the operator of approximately
96%
of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and
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•
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review and verification of historical production data, which data is based on actual production as reported by us;
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•
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preparation of reserve estimates by our Vice President–Reservoir Engineering or under his direct supervision;
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•
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review by our Vice President–Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
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•
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direct reporting responsibilities by our Vice President–Reservoir Engineering to our Chief Executive Officer;
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•
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verification of property ownership by our land department; and
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•
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no employee’s compensation is tied to the amount of reserves booked.
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December 31,
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2015
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2014
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2013
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Estimated proved developed reserves:
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Oil (Bbls)
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60,569,398
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43,885,835
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19,789,965
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Natural gas (Mcf)
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96,871,109
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68,264,113
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31,428,756
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Natural gas liquids (Bbls)
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15,418,353
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11,221,428
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4,973,493
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Total (BOE)
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92,132,936
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66,484,615
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30,001,584
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Estimated proved undeveloped reserves:
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Oil (Bbls)
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45,409,313
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31,803,754
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22,810,887
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Natural gas (Mcf)
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52,631,635
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43,341,147
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30,250,740
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Natural gas liquids (Bbls)
|
|
10,585,791
|
|
|
7,320,504
|
|
|
5,732,231
|
|
||
|
Total (BOE)
|
|
64,767,043
|
|
|
46,347,783
|
|
|
33,584,908
|
|
||
|
Estimated Net Proved Reserves:
|
|
|
|
|
|
|
|
|
|||
|
Oil (Bbls)
|
|
105,978,711
|
|
|
75,689,589
|
|
|
42,600,852
|
|
||
|
Natural gas (Mcf)
|
|
149,502,744
|
|
|
111,605,260
|
|
|
61,679,496
|
|
||
|
Natural gas liquids (Bbls)
|
|
26,004,144
|
|
|
18,541,932
|
|
|
10,705,724
|
|
||
|
Total (BOE)
(1)
|
|
156,899,979
|
|
|
112,832,398
|
|
|
63,586,492
|
|
||
|
Percent proved developed
|
|
58.7
|
%
|
|
58.9
|
%
|
|
47.2
|
%
|
||
|
(1)
|
Estimates of reserves as of
December 31, 2015
,
2014
and
2013
were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended
December 31, 2015
,
2014
and
2013
, respectively, in accordance with SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
|
|
|
(MBOE)
|
|
|
Beginning proved undeveloped reserves at December 31, 2014
|
46,348
|
|
|
Undeveloped reserves transferred to developed
|
(13,680
|
)
|
|
Revisions
|
(12,656
|
)
|
|
Extensions and discoveries
|
44,755
|
|
|
Ending proved undeveloped reserves at December 31, 2015
|
64,767
|
|
|
|
Historical
|
||||||||||
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
Production Data:
|
|
|
|
|
|
||||||
|
Oil (Bbls)
|
9,081,135
|
|
|
5,381,576
|
|
|
2,022,749
|
|
|||
|
Natural gas (Mcf)
|
7,931,237
|
|
|
4,345,916
|
|
|
1,730,497
|
|
|||
|
Natural gas liquids (Bbls)
|
1,677,623
|
|
|
1,001,991
|
|
|
361,079
|
|
|||
|
Combined volumes (BOE)
|
12,080,631
|
|
|
7,107,886
|
|
|
2,672,244
|
|
|||
|
Daily combined volumes (BOE/d)
|
33,098
|
|
|
19,474
|
|
|
7,321
|
|
|||
|
|
|
|
|
|
|
||||||
|
Average Prices:
|
|
|
|
|
|
||||||
|
Oil (per Bbl)
|
$
|
44.68
|
|
|
$
|
83.48
|
|
|
$
|
93.32
|
|
|
Natural gas (per Mcf)
|
2.47
|
|
|
4.15
|
|
|
3.61
|
|
|||
|
Natural gas liquids (per Bbl)
|
12.77
|
|
|
28.39
|
|
|
36.00
|
|
|||
|
Combined (per BOE)
|
36.98
|
|
|
69.74
|
|
|
77.84
|
|
|||
|
Oil, hedged($ per Bbl)
(1)
|
60.63
|
|
|
85.42
|
|
|
89.75
|
|
|||
|
Average price, hedged($ per BOE)
(1)
|
48.97
|
|
|
71.21
|
|
|
75.14
|
|
|||
|
|
|
|
|
|
|
||||||
|
Average Costs per BOE:
|
|
|
|
|
|
||||||
|
Lease operating expense
|
$
|
6.84
|
|
|
$
|
7.79
|
|
|
$
|
7.92
|
|
|
Production and ad valorem taxes
|
2.73
|
|
|
4.59
|
|
|
4.83
|
|
|||
|
Gathering and transportation expense
|
0.50
|
|
|
0.46
|
|
|
0.34
|
|
|||
|
General and administrative - cash component
|
1.11
|
|
|
1.61
|
|
|
3.47
|
|
|||
|
Total operating expense - cash
|
11.18
|
|
|
14.45
|
|
|
16.56
|
|
|||
|
|
|
|
|
|
|
||||||
|
General and administrative - non-cash component
|
1.54
|
|
|
1.38
|
|
|
0.66
|
|
|||
|
Depreciation, depletion, and amortization
|
18.02
|
|
|
23.92
|
|
|
24.92
|
|
|||
|
Interest expense
|
3.44
|
|
|
4.86
|
|
|
3.02
|
|
|||
|
Total expenses
|
23.00
|
|
|
30.16
|
|
|
28.60
|
|
|||
|
(1)
|
Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.
|
|
|
|
Developed Acreage
(1)
|
|
Undeveloped Acreage
(2)
|
|
Total Acreage
(3)
|
||||||||||||
|
Basin
|
|
Gross
(4)
|
|
Net
(5)
|
|
Gross
(4)
|
|
Net
(5)
|
|
Gross
(4)
|
|
Net
(5)
|
||||||
|
Permian
|
|
65,119
|
|
|
62,763
|
|
|
40,150
|
|
|
21,920
|
|
|
105,269
|
|
|
84,683
|
|
|
(1)
|
Developed acres are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.
|
|
(2)
|
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
|
|
(3)
|
Does not include Viper’s mineral interests but does include
22,500
gross (
16,811
net) leasehold acres that we own underlying our mineral interests.
|
|
(4)
|
A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
|
|
(5)
|
A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
|
|
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
||||||||||||||||||||
|
Basin
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||||||
|
Permian
|
|
15,305
|
|
|
6,007
|
|
|
23,312
|
|
|
15,142
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|
21
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
8
|
|
|
6
|
|
|
40
|
|
|
31
|
|
|
52
|
|
|
43
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
71
|
|
|
57
|
|
|
53
|
|
|
43
|
|
|
31
|
|
|
26
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
Productive
|
79
|
|
|
63
|
|
|
93
|
|
|
74
|
|
|
83
|
|
|
69
|
|
|
Dry
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
•
|
the location of wells;
|
|
•
|
the method of drilling and casing wells;
|
|
•
|
the timing of construction or drilling activities, including seasonal wildlife closures;
|
|
•
|
the rates of production or “allowables”;
|
|
•
|
the surface use and restoration of properties upon which wells are drilled;
|
|
•
|
the plugging and abandoning of wells; and
|
|
•
|
notice to, and consultation with, surface owners and other third parties.
|
|
•
|
the domestic and foreign supply of oil and natural gas;
|
|
•
|
the level of prices and expectations about future prices of oil and natural gas;
|
|
•
|
the level of global oil and natural gas exploration and production;
|
|
•
|
the cost of exploring for, developing, producing and delivering oil and natural gas;
|
|
•
|
the price and quantity of foreign imports;
|
|
•
|
political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;
|
|
•
|
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
|
|
•
|
speculative trading in crude oil and natural gas derivative contracts;
|
|
•
|
the level of consumer product demand;
|
|
•
|
weather conditions and other natural disasters;
|
|
•
|
risks associated with operating drilling rigs;
|
|
•
|
technological advances affecting energy consumption;
|
|
•
|
the price and availability of alternative fuels;
|
|
•
|
domestic and foreign governmental regulations and taxes;
|
|
•
|
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
|
|
•
|
the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; and
|
|
•
|
overall domestic and global economic conditions.
|
|
•
|
our proved reserves;
|
|
•
|
the volume of oil and natural gas we are able to produce from existing wells;
|
|
•
|
the prices at which our oil and natural gas are sold;
|
|
•
|
our ability to acquire, locate and produce economically new reserves; and
|
|
•
|
our ability to borrow under our credit facility.
|
|
•
|
recoverable reserves;
|
|
•
|
future oil and natural gas prices and their applicable differentials;
|
|
•
|
operating costs; and
|
|
•
|
potential environmental and other liabilities.
|
|
•
|
unusual or unexpected geological formations;
|
|
•
|
loss of drilling fluid circulation;
|
|
•
|
title problems;
|
|
•
|
facility or equipment malfunctions;
|
|
•
|
unexpected operational events;
|
|
•
|
shortages or delivery delays of equipment and services;
|
|
•
|
compliance with environmental and other governmental requirements; and
|
|
•
|
adverse weather conditions.
|
|
•
|
our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to the senior notes, including any repurchase obligations that may arise thereunder;
|
|
•
|
a significant portion of our cash flows could be used to service the senior notes and our other indebtedness, which could reduce the funds available to us for operations and other purposes;
|
|
•
|
a high level of debt could increase our vulnerability to general adverse economic and industry conditions;
|
|
•
|
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
|
|
•
|
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
|
|
•
|
our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry;
|
|
•
|
a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;
|
|
•
|
a high level of debt could limit our ability to access the capital markets to raise capital on favorable terms;
|
|
•
|
a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
|
|
•
|
we may be vulnerable to interest rate increases, as our borrowings under our revolving credit facility are at variable interest rates.
|
|
•
|
incur or guarantee additional indebtedness;
|
|
•
|
make certain investments;
|
|
•
|
create additional liens;
|
|
•
|
sell or transfer assets;
|
|
•
|
issue preferred stock;
|
|
•
|
merge or consolidate with another entity;
|
|
•
|
pay dividends or make other distributions;
|
|
•
|
designate certain of our subsidiaries as unrestricted subsidiaries;
|
|
•
|
create unrestricted subsidiaries;
|
|
•
|
engage in transactions with affiliates; and
|
|
•
|
enter into certain swap agreements.
|
|
•
|
permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;
|
|
•
|
permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
|
|
•
|
provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.
|
|
•
|
our quarterly or annual operating results;
|
|
•
|
changes in our earnings estimates;
|
|
•
|
investment recommendations by securities analysts following our business or our industry;
|
|
•
|
additions or departures of key personnel;
|
|
•
|
changes in the business, earnings estimates or market perceptions of our competitors;
|
|
•
|
our failure to achieve operating results consistent with securities analysts’ projections;
|
|
•
|
changes in industry, general market or economic conditions; and
|
|
•
|
announcements of legislative or regulatory changes.
|
|
•
|
provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;
|
|
•
|
limitations on the ability of our stockholders to call a special meeting and act by written consent;
|
|
•
|
the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;
|
|
•
|
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;
|
|
•
|
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and
|
|
•
|
the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.
|
|
|
High
|
|
Low
|
||||
|
2015
|
|
|
|
||||
|
1st Quarter
|
$
|
78.75
|
|
|
$
|
55.53
|
|
|
2nd Quarter
|
$
|
85.82
|
|
|
$
|
73.36
|
|
|
3rd Quarter
|
$
|
77.36
|
|
|
$
|
60.28
|
|
|
4th Quarter
|
$
|
82.19
|
|
|
$
|
61.51
|
|
|
2014
|
|
|
|
||||
|
1st Quarter
|
$
|
70.99
|
|
|
$
|
44.02
|
|
|
2nd Quarter
|
$
|
93.33
|
|
|
$
|
64.05
|
|
|
3rd Quarter
|
$
|
90.48
|
|
|
$
|
70.66
|
|
|
4th Quarter
|
$
|
76.94
|
|
|
$
|
51.69
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
(In thousands, except per share amounts)
|
2015
|
|
2014
|
|
2013
|
|
2012
(1)
|
|
2011
(2)
|
||||||||||
|
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Total revenues
|
$
|
446,733
|
|
|
$
|
495,718
|
|
|
$
|
208,002
|
|
|
$
|
74,962
|
|
|
$
|
49,366
|
|
|
Total costs and expenses
|
1,187,002
|
|
|
283,048
|
|
|
112,808
|
|
|
57,655
|
|
|
34,219
|
|
|||||
|
Income from operations
|
(740,269
|
)
|
|
212,670
|
|
|
95,194
|
|
|
17,307
|
|
|
15,147
|
|
|||||
|
Other income (expense)
|
(8,831
|
)
|
|
92,286
|
|
|
(8,853
|
)
|
|
1,075
|
|
|
(15,533
|
)
|
|||||
|
Income (loss) before income taxes
|
(749,100
|
)
|
|
304,956
|
|
|
86,341
|
|
|
18,382
|
|
|
(386
|
)
|
|||||
|
Provision for (benefit from) income taxes
|
(201,310
|
)
|
|
108,985
|
|
|
31,754
|
|
|
54,903
|
|
|
—
|
|
|||||
|
Net income (loss)
|
(547,790
|
)
|
|
195,971
|
|
|
54,587
|
|
|
(36,521
|
)
|
|
(386
|
)
|
|||||
|
Less: Net income attributable to noncontrolling interest
|
2,838
|
|
|
2,216
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
(550,628
|
)
|
|
$
|
193,755
|
|
|
$
|
54,587
|
|
|
$
|
(36,521
|
)
|
|
$
|
(386
|
)
|
|
Earnings per common share
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Basic
|
$
|
(8.74
|
)
|
|
$
|
3.67
|
|
|
$
|
1.30
|
|
|
|
|
|
||||
|
Diluted
|
$
|
(8.74
|
)
|
|
$
|
3.64
|
|
|
$
|
1.29
|
|
|
|
|
|
||||
|
Weighted average common shares outstanding
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Basic
|
63,019
|
|
|
52,826
|
|
|
42,015
|
|
|
|
|
|
|||||||
|
Diluted
|
63,019
|
|
|
53,297
|
|
|
42,255
|
|
|
|
|
|
|||||||
|
Pro forma information
(3)
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Income (loss) before income taxes, as reported
|
|
|
|
|
|
|
$
|
18,382
|
|
|
$
|
(386
|
)
|
||||||
|
Pro forma provision for income taxes
|
|
|
|
|
|
|
6,553
|
|
|
—
|
|
||||||||
|
Pro forma net income (loss)
|
|
|
|
|
|
|
$
|
11,829
|
|
|
$
|
(386
|
)
|
||||||
|
Pro forma earnings per common share
(4)
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Basic
|
|
|
|
|
|
|
$
|
0.60
|
|
|
|
||||||||
|
Diluted
|
|
|
|
|
|
|
$
|
0.60
|
|
|
|
||||||||
|
|
As of December 31,
|
|||||||||||||
|
(In thousands)
|
2015
|
|
2014
|
|
2013
|
|
2012
(1)
|
|
2011
(2)
|
|||||
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|||||
|
Cash and cash equivalents
|
20,115
|
|
|
30,183
|
|
|
15,555
|
|
|
26,358
|
|
|
6,959
|
|
|
Net property and equipment
|
2,597,625
|
|
|
2,791,807
|
|
|
1,446,337
|
|
|
554,242
|
|
|
221,149
|
|
|
Total assets
|
2,758,412
|
|
|
3,095,481
|
|
|
1,521,614
|
|
|
606,701
|
|
|
263,578
|
|
|
Current liabilities
|
141,421
|
|
|
266,729
|
|
|
121,320
|
|
|
79,232
|
|
|
42,298
|
|
|
Long-term debt
|
495,500
|
|
|
673,500
|
|
|
460,000
|
|
|
193
|
|
|
85,000
|
|
|
Total Stockholders’/ Members’ equity
(5)
|
1,875,972
|
|
|
1,751,011
|
|
|
845,541
|
|
|
462,068
|
|
|
129,037
|
|
|
Total equity
|
2,108,973
|
|
|
1,985,213
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
(In thousands)
|
2015
|
|
2014
|
|
2013
|
|
2012
(1)
|
|
2011
(2)
|
||||||||||
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Net cash provided by operating activities
|
$
|
416,501
|
|
|
$
|
356,389
|
|
|
$
|
155,777
|
|
|
$
|
49,692
|
|
|
$
|
30,998
|
|
|
Net cash used in investing activities
|
(895,050
|
)
|
|
(1,481,997
|
)
|
|
(940,140
|
)
|
|
(183,078
|
)
|
|
(81,108
|
)
|
|||||
|
Net cash provided by financing activities
|
468,481
|
|
|
1,140,236
|
|
|
773,560
|
|
|
152,785
|
|
|
52,950
|
|
|||||
|
|
Year Ended December 31,
|
||||||||||||||||||
|
(In thousands)
|
2015
|
|
2014
|
|
2013
|
|
2012
(1)
|
|
2011
(2)
|
||||||||||
|
Adjusted EBITDA
(6)
|
$
|
449,245
|
|
|
$
|
398,334
|
|
|
$
|
157,604
|
|
|
$
|
42,783
|
|
|
$
|
31,721
|
|
|
(1)
|
The year ended December 31, 2012 reflects (a) the combined historical financial data of Windsor Permian LLC and Windsor UT LLC, which we sometimes refer to as the Predecessors, due to the transfer of a business between entities under common control and (b) the results of operations attributable to the acquisition of properties from Gulfport Energy Corporation beginning October 11, 2012, the closing date of the property acquisition.
|
|
(2)
|
The year ended December 31, 2011 reflects the combined historical financial data of Windsor Permian LLC and Windsor UT LLC due to the transfer of a business between entities under common control.
|
|
(3)
|
Diamondback was formed as a holding company on December 30, 2011, and did not conduct any material business operations until October 11, 2012 when Diamondback merged with its parent entity, Diamondback Energy LLC, with Diamondback continuing as the surviving entity. Diamondback is a subchapter C corporation under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision for 2012 as if the Company and the Predecessors were subject to income taxes since December 31, 2011. For 2011 comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of the Company and the Predecessors had been subject to federal income tax as a subchapter C corporation since inception. If the earnings of the Company and the Predecessors had been subject to federal income tax as a subchapter C corporation since inception, we would have incurred net operating losses for income tax purposes in each period. We would have been in a net deferred tax asset position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s deferred tax asset balance to zero. A valuation allowance to reduce each period’s deferred tax asset would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respected benefits for income taxes, with the resulting tax expenses for 2011 of zero. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. See Note 2 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
|
|
(4)
|
The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the merger of Diamondback Energy LLC into Diamondback were outstanding for the entire year. Diluted earnings per share reflects the potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock awards and units were fully vested. During periods in which the Company realizes a net loss, options and restricted stock awards would not be dilutive to net loss per share and conversion into common stock is assumed not to occur.
|
|
(5)
|
For the years ended
December 31, 2015
and
2014
, total stockholders’ equity excludes
$233.0 million
and
$234.2 million
, respectively, of noncontrolling interest related to Viper Energy Partners LP. There was no equity related to noncontrolling interest for the years ended
December 31, 2013
,
2012
and
2011
.
|
|
(6)
|
Adjusted EBITDA is a supplemental non-GAAP financial measure. For our definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) see “–Non-GAAP financial measure and reconciliation” below.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
(In thousands)
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
|
Net income (loss):
|
$
|
(547,790
|
)
|
|
$
|
195,971
|
|
|
$
|
54,587
|
|
|
$
|
(36,521
|
)
|
|
$
|
(386
|
)
|
|
Change in the fair value of open non-hedge derivative instruments, net
|
112,918
|
|
|
(117,109
|
)
|
|
(5,346
|
)
|
|
(8,057
|
)
|
|
12,972
|
|
|||||
|
Interest expense (income)
|
41,510
|
|
|
34,515
|
|
|
8,059
|
|
|
3,610
|
|
|
2,528
|
|
|||||
|
Depreciation, depletion and amortization expense
|
217,697
|
|
|
170,005
|
|
|
66,597
|
|
|
26,273
|
|
|
16,104
|
|
|||||
|
Impairment of oil and natural gas properties
|
814,798
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Non-cash equity-based compensation expense
|
24,572
|
|
|
14,253
|
|
|
2,724
|
|
|
3,482
|
|
|
544
|
|
|||||
|
Capitalized equity-based compensation expense
|
(6,043
|
)
|
|
(4,437
|
)
|
|
(972
|
)
|
|
(1,005
|
)
|
|
(106
|
)
|
|||||
|
Asset retirement obligation accretion expense
|
833
|
|
|
467
|
|
|
201
|
|
|
98
|
|
|
65
|
|
|||||
|
Income tax provision (benefit)
|
(201,310
|
)
|
|
108,985
|
|
|
31,754
|
|
|
54,903
|
|
|
—
|
|
|||||
|
Non-controlling interest
|
(7,940
|
)
|
|
(4,316
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Adjusted EBITDA
|
$
|
449,245
|
|
|
$
|
398,334
|
|
|
$
|
157,604
|
|
|
$
|
42,783
|
|
|
$
|
31,721
|
|
|
|
2015
|
|
2014
|
|
2013
|
|||
|
Estimated Net Proved Reserves:
|
|
|
|
|
|
|||
|
Oil (Bbls)
|
105,978,711
|
|
|
75,689,589
|
|
|
42,600,852
|
|
|
Natural gas (Mcf)
|
149,502,744
|
|
|
111,605,260
|
|
|
61,679,496
|
|
|
Natural gas liquids (Bbls)
|
26,004,144
|
|
|
18,541,932
|
|
|
10,705,724
|
|
|
Total (BOE)
|
156,899,979
|
|
|
112,832,398
|
|
|
63,586,492
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
Unweighted Arithmetic Average
|
||||||||||
|
|
First-Day-of-the-Month Prices
|
||||||||||
|
Oil (per Bbl)
|
$
|
45.07
|
|
|
$
|
87.15
|
|
|
$
|
92.59
|
|
|
Natural gas (per Mcf)
|
$
|
1.83
|
|
|
$
|
4.85
|
|
|
$
|
4.13
|
|
|
Natural gas liquids (per Bbl)
|
$
|
12.56
|
|
|
$
|
30.09
|
|
|
$
|
37.82
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
(in thousands, except Bbl, Mcf and BOE amounts)
|
||||||||||
|
Revenues
|
|
|
|
|
|
|
||||||
|
Oil, natural gas liquids and natural gas
|
|
$
|
446,733
|
|
|
$
|
495,718
|
|
|
$
|
208,002
|
|
|
Operating Expenses
|
|
|
|
|
|
|
||||||
|
Lease operating expense
|
|
82,625
|
|
|
55,384
|
|
|
21,157
|
|
|||
|
Production and ad valorem taxes
|
|
32,990
|
|
|
32,638
|
|
|
12,899
|
|
|||
|
Gathering and transportation expense
|
|
6,091
|
|
|
3,288
|
|
|
918
|
|
|||
|
Depreciation, depletion and amortization
|
|
217,697
|
|
|
170,005
|
|
|
66,597
|
|
|||
|
Impairment of oil and natural gas properties
|
|
814,798
|
|
|
—
|
|
|
—
|
|
|||
|
General and administrative
|
|
31,968
|
|
|
21,266
|
|
|
11,036
|
|
|||
|
Asset retirement obligation accretion expense
|
|
833
|
|
|
467
|
|
|
201
|
|
|||
|
Total expenses
|
|
1,187,002
|
|
|
283,048
|
|
|
112,808
|
|
|||
|
Income (loss) from operations
|
|
(740,269
|
)
|
|
212,670
|
|
|
95,194
|
|
|||
|
Net interest expense
|
|
(41,510
|
)
|
|
(34,514
|
)
|
|
(8,058
|
)
|
|||
|
Other income
|
|
728
|
|
|
677
|
|
|
1,077
|
|
|||
|
Other expense
|
|
—
|
|
|
(1,416
|
)
|
|
—
|
|
|||
|
Gain (loss) on derivative instruments, net
|
|
31,951
|
|
|
127,539
|
|
|
(1,872
|
)
|
|||
|
Total other income (expense), net
|
|
(8,831
|
)
|
|
92,286
|
|
|
(8,853
|
)
|
|||
|
Income (loss) before income taxes
|
|
(749,100
|
)
|
|
304,956
|
|
|
86,341
|
|
|||
|
Income tax provision (benefit)
|
|
(201,310
|
)
|
|
108,985
|
|
|
31,754
|
|
|||
|
Net income (loss)
|
|
(547,790
|
)
|
|
195,971
|
|
|
54,587
|
|
|||
|
Less: Net income attributable to noncontrolling interest
|
|
2,838
|
|
|
2,216
|
|
|
—
|
|
|||
|
Net income (loss) attributable to Diamondback Energy, Inc.
|
|
$
|
(550,628
|
)
|
|
$
|
193,755
|
|
|
$
|
54,587
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
(in thousands, except Bbl, Mcf and BOE amounts)
|
||||||||||
|
Production Data:
|
|
|
|
|
|
|
||||||
|
Oil (Bbls)
|
|
9,081,135
|
|
|
5,381,576
|
|
|
2,022,749
|
|
|||
|
Natural gas (Mcf)
|
|
7,931,237
|
|
|
4,345,916
|
|
|
1,730,497
|
|
|||
|
Natural gas liquids (Bbls)
|
|
1,677,623
|
|
|
1,001,991
|
|
|
361,079
|
|
|||
|
Combined volumes (BOE)
|
|
12,080,631
|
|
|
7,107,886
|
|
|
2,672,244
|
|
|||
|
Daily combined volumes (BOE/d)
|
|
33,098
|
|
|
19,474
|
|
|
7,321
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Average Prices:
|
|
|
|
|
|
|
||||||
|
Oil (per Bbl)
|
|
$
|
44.68
|
|
|
$
|
83.48
|
|
|
$
|
93.32
|
|
|
Natural gas (per Mcf)
|
|
2.47
|
|
|
4.15
|
|
|
3.61
|
|
|||
|
Natural gas liquids (per Bbl)
|
|
12.77
|
|
|
28.39
|
|
|
36.00
|
|
|||
|
Combined (per BOE)
|
|
36.98
|
|
|
69.74
|
|
|
77.84
|
|
|||
|
Oil, hedged($ per Bbl)
(1)
|
|
60.63
|
|
|
85.42
|
|
|
89.75
|
|
|||
|
Average price, hedged($ per BOE)
(1)
|
|
48.97
|
|
|
71.21
|
|
|
75.14
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
Average Costs per BOE:
|
|
|
|
|
|
|
||||||
|
Lease operating expense
|
|
$
|
6.84
|
|
|
$
|
7.79
|
|
|
$
|
7.92
|
|
|
Production and ad valorem taxes
|
|
2.73
|
|
|
4.59
|
|
|
4.83
|
|
|||
|
Gathering and transportation expense
|
|
0.50
|
|
|
0.46
|
|
|
0.34
|
|
|||
|
General and administrative - cash component
|
|
1.11
|
|
|
1.61
|
|
|
3.47
|
|
|||
|
Total operating expense - cash
|
|
11.18
|
|
|
14.45
|
|
|
16.56
|
|
|||
|
|
|
|
|
|
|
|
||||||
|
General and administrative - non-cash component
|
|
1.54
|
|
|
1.38
|
|
|
0.66
|
|
|||
|
Depreciation, depletion, and amortization
|
|
18.02
|
|
|
23.92
|
|
|
24.92
|
|
|||
|
Interest expense
|
|
3.44
|
|
|
4.86
|
|
|
3.02
|
|
|||
|
Total expenses
|
|
23.00
|
|
|
30.16
|
|
|
28.60
|
|
|||
|
(1)
|
Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.
|
|
|
Change in prices
|
|
Production volumes
(1)
|
|
Total net dollar effect of change
|
||||||
|
|
|
|
|
|
(in thousands)
|
||||||
|
Effect of changes in price:
|
|
|
|
|
|
||||||
|
Oil
|
$
|
(38.80
|
)
|
|
9,081,135
|
|
|
$
|
(352,356
|
)
|
|
|
Natural gas liquids
|
$
|
(15.62
|
)
|
|
1,677,623
|
|
|
$
|
(26,204
|
)
|
|
|
Natural gas
|
$
|
(1.68
|
)
|
|
7,931,237
|
|
|
$
|
(13,324
|
)
|
|
|
Total revenues due to change in price
|
|
|
|
|
$
|
(391,884
|
)
|
||||
|
|
|
|
|
|
|
||||||
|
|
Change in production volumes
(1)
|
|
Prior period average prices
|
|
Total net dollar effect of change
|
||||||
|
|
|
|
|
|
(in thousands)
|
||||||
|
Effect of changes in production volumes:
|
|
|
|
|
|
||||||
|
Oil
|
3,699,559
|
|
|
$
|
83.48
|
|
|
$
|
308,839
|
|
|
|
Natural gas liquids
|
675,632
|
|
|
$
|
28.39
|
|
|
$
|
19,181
|
|
|
|
Natural gas
|
3,585,321
|
|
|
$
|
4.15
|
|
|
$
|
14,879
|
|
|
|
Total revenues due to change in production volumes
|
|
|
|
|
$
|
342,899
|
|
||||
|
Total change in revenues
|
|
|
|
|
$
|
(48,985
|
)
|
||||
|
(1)
|
Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas.
|
|
|
Year Ended December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in thousands, except BOE amounts)
|
||||||
|
Depletion of proved oil and natural gas properties
|
$
|
216,056
|
|
|
$
|
168,674
|
|
|
Depreciation of other property and equipment
|
1,641
|
|
|
1,331
|
|
||
|
Depreciation, depletion and amortization expense
|
$
|
217,697
|
|
|
$
|
170,005
|
|
|
Oil and natural gas properties depreciation, depletion and amortization expense per BOE
|
$
|
17.84
|
|
|
$
|
23.79
|
|
|
Total depreciation, depletion and amortization expense per BOE
|
$
|
18.02
|
|
|
$
|
23.92
|
|
|
|
Change in prices
|
|
Production volumes
(1)
|
|
Total net dollar effect of change
|
||||||
|
|
|
|
|
|
(in thousands)
|
||||||
|
Effect of changes in price:
|
|
|
|
|
|
||||||
|
Oil
|
$
|
(9.84
|
)
|
|
5,381,576
|
|
|
$
|
(52,959
|
)
|
|
|
Natural gas liquids
|
$
|
(7.61
|
)
|
|
1,001,991
|
|
|
$
|
(7,625
|
)
|
|
|
Natural gas
|
$
|
0.54
|
|
|
4,345,916
|
|
|
$
|
2,345
|
|
|
|
Total revenues due to change in price
|
|
|
|
|
$
|
(58,239
|
)
|
||||
|
|
|
|
|
|
|
||||||
|
|
Change in production volumes
(1)
|
|
Prior period average prices
|
|
Total net dollar effect of change
|
||||||
|
|
|
|
|
|
(in thousands)
|
||||||
|
Effect of changes in production volumes:
|
|
|
|
|
|
||||||
|
Oil
|
3,358,827
|
|
|
$
|
93.32
|
|
|
$
|
313,444
|
|
|
|
Natural gas liquids
|
640,912
|
|
|
$
|
36.00
|
|
|
$
|
23,071
|
|
|
|
Natural gas
|
2,615,419
|
|
|
$
|
3.61
|
|
|
$
|
9,440
|
|
|
|
Total revenues due to change in production volumes
|
|
|
|
|
$
|
345,955
|
|
||||
|
Total change in revenues
|
|
|
|
|
$
|
287,716
|
|
||||
|
(1)
|
Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas.
|
|
|
Year Ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
|
|
|
||||
|
|
(in thousands, except BOE amounts)
|
||||||
|
Depletion of proved oil and natural gas properties
|
$
|
168,674
|
|
|
$
|
65,821
|
|
|
Depreciation of other property and equipment
|
1,331
|
|
|
776
|
|
||
|
Depreciation, depletion and amortization expense
|
$
|
170,005
|
|
|
$
|
66,597
|
|
|
Oil and natural gas properties depreciation, depletion and amortization expense per BOE
|
$
|
23.79
|
|
|
$
|
24.63
|
|
|
Total depreciation, depletion and amortization expense per BOE
|
$
|
23.92
|
|
|
$
|
24.92
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
Net cash provided by operating activities
|
$
|
416,501
|
|
|
$
|
356,389
|
|
|
$
|
155,777
|
|
|
Net cash used in investing activities
|
(895,050
|
)
|
|
(1,481,997
|
)
|
|
(940,140
|
)
|
|||
|
Net cash provided by financing activities
|
$
|
468,481
|
|
|
$
|
1,140,236
|
|
|
$
|
773,560
|
|
|
Net change in cash
|
$
|
(10,068
|
)
|
|
$
|
14,628
|
|
|
$
|
(10,803
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
Drilling, completion and infrastructure
|
$
|
(419,512
|
)
|
|
$
|
(499,848
|
)
|
|
$
|
(297,713
|
)
|
|
Acquisition of leasehold interests
|
(437,455
|
)
|
|
(845,826
|
)
|
|
(177,343
|
)
|
|||
|
Acquisition of Gulfport properties
|
—
|
|
|
—
|
|
|
(18,550
|
)
|
|||
|
Acquisition of royalty interests
|
(43,907
|
)
|
|
(57,689
|
)
|
|
(444,083
|
)
|
|||
|
Purchase of other property and equipment
|
(1,213
|
)
|
|
(44,213
|
)
|
|
(2,234
|
)
|
|||
|
Proceeds from sale of assets
|
9,739
|
|
|
56
|
|
|
72
|
|
|||
|
Equity investments
|
(2,702
|
)
|
|
(34,477
|
)
|
|
—
|
|
|||
|
Settlement of non-hedge derivative instruments
|
—
|
|
|
—
|
|
|
(289
|
)
|
|||
|
Net cash used in investing activities
|
$
|
(895,050
|
)
|
|
$
|
(1,481,997
|
)
|
|
$
|
(940,140
|
)
|
|
Financial Covenant
|
Required Ratio
|
|
Ratio of total debt to EBITDAX
|
Not greater than 4.0 to 1.0
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
|
Financial Covenant
|
Required Ratio
|
|
Ratio of total debt to EBITDAX
|
Not greater than 4.0 to 1.0
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
|
•
|
$210.0 million
to
$315.0 million
will be spent on drilling and completing
30
to
70
gross (
25
to
58
net) operated horizontal wells focused in Midland, Andrews, Upton, Martin and Dawson Counties;
|
|
•
|
$25.0 million
to
$35.0 million
will be spent on infrastructure; and
|
|
•
|
$15.0 million
to
$25.0 million
will be spent on non-operated activity and other expenditures.
|
|
|
Payments Due by Period
|
||||||||||||||||||
|
|
2016
|
|
2017-2018
|
|
2019-2020
|
|
Thereafter
|
|
Total
|
||||||||||
|
|
(in thousands)
|
||||||||||||||||||
|
Secured revolving credit facility
(1)
|
$
|
—
|
|
|
$
|
11,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11,000
|
|
|
Interest expense related to the secured revolving credit facility
|
2,813
|
|
|
4,454
|
|
|
—
|
|
|
—
|
|
|
$
|
7,267
|
|
||||
|
Senior notes
|
—
|
|
|
—
|
|
|
—
|
|
|
450,000
|
|
|
$
|
450,000
|
|
||||
|
Interest expense
the senior notes
(2)
|
34,313
|
|
|
68,626
|
|
|
68,626
|
|
|
34,313
|
|
|
$
|
205,878
|
|
||||
|
Viper's secured revolving credit facility
(1)
|
—
|
|
|
—
|
|
|
—
|
|
|
34,500
|
|
|
$
|
34,500
|
|
||||
|
Interest and commitment fees under Viper's credit agreement
(3)
|
2,636
|
|
|
750
|
|
|
1,500
|
|
|
386
|
|
|
$
|
5,272
|
|
||||
|
Asset retirement obligations
(4)
|
193
|
|
|
—
|
|
|
—
|
|
|
12,518
|
|
|
$
|
12,711
|
|
||||
|
Drilling commitments
(5)
|
29,536
|
|
|
36,759
|
|
|
589
|
|
|
—
|
|
|
$
|
66,884
|
|
||||
|
Operating lease obligations
|
1,935
|
|
|
4,026
|
|
|
3,498
|
|
|
9,583
|
|
|
$
|
19,042
|
|
||||
|
|
$
|
71,426
|
|
|
$
|
125,615
|
|
|
$
|
74,213
|
|
|
$
|
541,300
|
|
|
$
|
812,554
|
|
|
(1)
|
Includes the outstanding principal amount under the revolving credit facilities, the table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.
|
|
(2)
|
Interest represents the scheduled cash payments on the senior notes.
|
|
(3)
|
Includes only the minimum amount of interest and commitment fees due which, as of December 31, 2015, includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of Viper’s credit agreement.
|
|
(4)
|
Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note
6
of the notes to our consolidated financial statements set forth in Part IV, Item 15 of this Form 10-K.
|
|
(5)
|
Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on
December 31, 2015
.
|
|
(a)
|
Documents included in this report:
|
|
|
|
1. Financial Statements
|
|
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
||
|
|
|
|
|
|
2. Financial Statement Schedules
|
|
|
|
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s consolidated financial statements and related notes.
|
|
|
|
|
|
|
|
3. Exhibits
|
|
|
|
The Exhibit Index beginning on page E–1 of this report is incorporated herein by reference.
|
|
|
|
|
|
DIAMONDBACK ENERGY, INC.
|
|
|
|
|
|
|
Date:
|
February 19, 2016
|
|
|
|
|
|
|
/s/ Travis D. Stice
|
|
|
|
|
Travis D. Stice
|
|
|
|
|
Chief Executive Officer
|
|
|
|
|
(Principal Executive Officer)
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
|
/s/ Steven E. West
|
|
Chairman of the Board and Director
|
|
February 19, 2016
|
|
Steven E. West
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Travis D. Stice
|
|
Chief Executive Officer and Director
|
|
February 19, 2016
|
|
Travis D. Stice
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
|
|
/s/ Michael P. Cross
|
|
Director
|
|
February 19, 2016
|
|
Michael P. Cross
|
|
|
|
|
|
|
|
|
|
|
|
/s/ David L. Houston
|
|
Director
|
|
February 19, 2016
|
|
David L. Houston
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Mark L. Plaumann
|
|
Director
|
|
February 19, 2016
|
|
Mark L. Plaumann
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Teresa L. Dick
|
|
Chief Financial Officer, Senior Vice President, and Assistant Secretary
|
|
February 19, 2016
|
|
Teresa L. Dick
|
|
(Principal Financial and Accounting Officer)
|
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(In thousands)
|
||||||
|
Assets
|
|
|
|
||||
|
Current assets:
|
|
|
|
||||
|
Cash and cash equivalents
|
$
|
20,115
|
|
|
$
|
30,183
|
|
|
Restricted cash
|
500
|
|
|
500
|
|
||
|
Accounts receivable:
|
|
|
|
||||
|
Joint interest and other
|
41,309
|
|
|
50,943
|
|
||
|
Oil and natural gas sales
|
36,004
|
|
|
43,050
|
|
||
|
Related party
|
1,591
|
|
|
4,001
|
|
||
|
Inventories
|
1,728
|
|
|
2,827
|
|
||
|
Derivative instruments
|
4,623
|
|
|
115,607
|
|
||
|
Prepaid expenses and other
|
2,875
|
|
|
4,600
|
|
||
|
Total current assets
|
108,745
|
|
|
251,711
|
|
||
|
Property and equipment
|
|
|
|
||||
|
Oil and natural gas properties, based on the full cost method of accounting ($1,106,816 and $773,520 excluded from amortization at December 31, 2015 and December 31, 2014, respectively)
|
3,955,373
|
|
|
3,118,597
|
|
||
|
Pipeline and gas gathering assets
|
7,174
|
|
|
7,174
|
|
||
|
Other property and equipment
|
48,621
|
|
|
48,180
|
|
||
|
Accumulated depletion, depreciation, amortization and impairment
|
(1,413,543
|
)
|
|
(382,144
|
)
|
||
|
Net property and equipment
|
2,597,625
|
|
|
2,791,807
|
|
||
|
Derivative instruments
|
—
|
|
|
1,934
|
|
||
|
Other assets
|
52,042
|
|
|
50,029
|
|
||
|
Total assets
|
$
|
2,758,412
|
|
|
$
|
3,095,481
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
||||
|
Current liabilities:
|
|
|
|
||||
|
Accounts payable-trade
|
$
|
20,008
|
|
|
$
|
26,230
|
|
|
Accounts payable-related party
|
217
|
|
|
—
|
|
||
|
Accrued capital expenditures
|
59,937
|
|
|
129,397
|
|
||
|
Other accrued liabilities
|
44,293
|
|
|
41,149
|
|
||
|
Revenues and royalties payable
|
16,966
|
|
|
30,000
|
|
||
|
Deferred income taxes
|
—
|
|
|
39,953
|
|
||
|
Total current liabilities
|
141,421
|
|
|
266,729
|
|
||
|
Long-term debt
|
495,500
|
|
|
673,500
|
|
||
|
Asset retirement obligations
|
12,518
|
|
|
8,447
|
|
||
|
Deferred income taxes
|
—
|
|
|
161,592
|
|
||
|
Total liabilities
|
649,439
|
|
|
1,110,268
|
|
||
|
Commitments and contingencies (Note 15)
|
|
|
|
|
|
||
|
Stockholders’ equity:
|
|
|
|
||||
|
Common stock, $0.01 par value, 100,000,000 shares authorized, 66,797,041 issued and outstanding at December 31, 2015; 56,887,583 issued and outstanding at December 31, 2014
|
668
|
|
|
569
|
|
||
|
Additional paid-in capital
|
2,229,664
|
|
|
1,554,174
|
|
||
|
Retained earnings
|
(354,360
|
)
|
|
196,268
|
|
||
|
Total Diamondback Energy, Inc. stockholders’ equity
|
1,875,972
|
|
|
1,751,011
|
|
||
|
Noncontrolling interest
|
233,001
|
|
|
234,202
|
|
||
|
Total equity
|
2,108,973
|
|
|
1,985,213
|
|
||
|
Total liabilities and equity
|
$
|
2,758,412
|
|
|
$
|
3,095,481
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands, except per share amounts)
|
||||||||||
|
Revenues:
|
|
|
|
|
|
||||||
|
Oil sales
|
$
|
405,715
|
|
|
$
|
449,244
|
|
|
$
|
188,753
|
|
|
Natural gas sales
|
16,952
|
|
|
8,662
|
|
|
3,715
|
|
|||
|
Natural gas sales - related party
|
2,640
|
|
|
9,366
|
|
|
2,534
|
|
|||
|
Natural gas liquid sales
|
18,882
|
|
|
13,408
|
|
|
8,304
|
|
|||
|
Natural gas liquid sales - related party
|
2,544
|
|
|
15,038
|
|
|
4,696
|
|
|||
|
Total revenues
|
446,733
|
|
|
495,718
|
|
|
208,002
|
|
|||
|
Costs and expenses:
|
|
|
|
|
|
||||||
|
Lease operating expenses
|
82,404
|
|
|
55,166
|
|
|
19,991
|
|
|||
|
Lease operating expenses - related party
|
221
|
|
|
218
|
|
|
1,166
|
|
|||
|
Production and ad valorem taxes
|
32,837
|
|
|
31,160
|
|
|
12,399
|
|
|||
|
Production and ad valorem taxes - related party
|
153
|
|
|
1,478
|
|
|
500
|
|
|||
|
Gathering and transportation
|
5,122
|
|
|
618
|
|
|
237
|
|
|||
|
Gathering and transportation - related party
|
969
|
|
|
2,670
|
|
|
681
|
|
|||
|
Depreciation, depletion and amortization
|
217,697
|
|
|
170,005
|
|
|
66,597
|
|
|||
|
Impairment of oil and natural gas properties
|
814,798
|
|
|
—
|
|
|
—
|
|
|||
|
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $18,529, $9,816 and $1,752 for the year ended December 31, 2015, 2014 and 2013, respectively)
|
29,640
|
|
|
19,921
|
|
|
9,870
|
|
|||
|
General and administrative expenses - related party
|
2,328
|
|
|
1,345
|
|
|
1,166
|
|
|||
|
Asset retirement obligation accretion expense
|
833
|
|
|
467
|
|
|
201
|
|
|||
|
Total costs and expenses
|
1,187,002
|
|
|
283,048
|
|
|
112,808
|
|
|||
|
Income (loss) from operations
|
(740,269
|
)
|
|
212,670
|
|
|
95,194
|
|
|||
|
Other income (expense)
|
|
|
|
|
|
||||||
|
Interest income (expense)
|
(41,510
|
)
|
|
(34,514
|
)
|
|
(8,058
|
)
|
|||
|
Other income
|
567
|
|
|
556
|
|
|
—
|
|
|||
|
Other income - related party
|
161
|
|
|
121
|
|
|
1,077
|
|
|||
|
Other expense
|
—
|
|
|
(1,416
|
)
|
|
—
|
|
|||
|
Gain (loss) on derivative instruments, net
|
31,951
|
|
|
127,539
|
|
|
(1,872
|
)
|
|||
|
Total other income (expense), net
|
(8,831
|
)
|
|
92,286
|
|
|
(8,853
|
)
|
|||
|
Income (loss) before income taxes
|
(749,100
|
)
|
|
304,956
|
|
|
86,341
|
|
|||
|
Provision for (benefit from) income taxes
|
(201,310
|
)
|
|
108,985
|
|
|
31,754
|
|
|||
|
Net income (loss)
|
(547,790
|
)
|
|
195,971
|
|
|
54,587
|
|
|||
|
Less: Net income attributable to noncontrolling interest
|
2,838
|
|
|
2,216
|
|
|
—
|
|
|||
|
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
(550,628
|
)
|
|
$
|
193,755
|
|
|
$
|
54,587
|
|
|
|
|
|
|
|
|
||||||
|
Earnings per common share
|
|
|
|
|
|
||||||
|
Basic
|
$
|
(8.74
|
)
|
|
$
|
3.67
|
|
|
$
|
1.30
|
|
|
Diluted
|
$
|
(8.74
|
)
|
|
$
|
3.64
|
|
|
$
|
1.29
|
|
|
Weighted average common shares outstanding
|
|
|
|
|
|
||||||
|
Basic
|
63,019
|
|
|
52,826
|
|
|
42,015
|
|
|||
|
Diluted
|
63,019
|
|
|
53,297
|
|
|
42,255
|
|
|||
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Retained Earnings
|
|
Non-Controlling Interest
|
|
|
||||||||||||
|
|
Shares
|
Amount
|
|
|
|
|
Total
|
||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
(In thousands)
|
||||||||||||||||||||
|
Balance December 31, 2012
|
36,986
|
|
$
|
370
|
|
|
$
|
513,772
|
|
|
$
|
(52,074
|
)
|
|
$
|
—
|
|
|
$
|
462,068
|
|
|
Stock-based compensation
|
—
|
|
—
|
|
|
2,724
|
|
|
—
|
|
|
—
|
|
|
2,724
|
|
|||||
|
Tax benefits related to stock-based compensation
|
—
|
|
—
|
|
|
749
|
|
|
—
|
|
|
—
|
|
|
749
|
|
|||||
|
Common shares issued in public offering, net of offering costs
|
9,775
|
|
98
|
|
|
321,814
|
|
|
—
|
|
|
—
|
|
|
321,912
|
|
|||||
|
Exercise of stock options and vesting of restricted stock units
|
345
|
|
3
|
|
|
3,498
|
|
|
—
|
|
|
—
|
|
|
3,501
|
|
|||||
|
Net income
|
—
|
|
—
|
|
|
—
|
|
|
54,587
|
|
|
—
|
|
|
54,587
|
|
|||||
|
Balance December 31, 2013
|
47,106
|
|
471
|
|
|
842,557
|
|
|
2,513
|
|
|
—
|
|
|
845,541
|
|
|||||
|
Net proceeds from issuance of common units - Viper Energy Partners LP
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
232,198
|
|
|
232,198
|
|
|||||
|
Unit-based compensation
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,102
|
|
|
2,102
|
|
|||||
|
Distribution to noncontrolling interest
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,314
|
)
|
|
(2,314
|
)
|
|||||
|
Stock-based compensation
|
—
|
|
—
|
|
|
12,152
|
|
|
—
|
|
|
—
|
|
|
12,152
|
|
|||||
|
Tax benefits related to stock-based compensation
|
—
|
|
—
|
|
|
(749
|
)
|
|
—
|
|
|
—
|
|
|
(749
|
)
|
|||||
|
Common shares issued in public offering, net of offering costs
|
9,200
|
|
92
|
|
|
689,390
|
|
|
—
|
|
|
—
|
|
|
689,482
|
|
|||||
|
Exercise of stock options and awards of restricted stock
|
518
|
|
5
|
|
|
7,075
|
|
|
—
|
|
|
—
|
|
|
7,080
|
|
|||||
|
Equity payment- Wexford Advisory Services (See Note 11)
|
64
|
|
1
|
|
|
3,749
|
|
|
—
|
|
|
—
|
|
|
3,750
|
|
|||||
|
Net income
|
—
|
|
—
|
|
|
—
|
|
|
193,755
|
|
|
2,216
|
|
|
195,971
|
|
|||||
|
Balance December 31, 2014
|
56,888
|
|
569
|
|
|
1,554,174
|
|
|
196,268
|
|
|
234,202
|
|
|
1,985,213
|
|
|||||
|
Unit-based compensation
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,929
|
|
|
3,929
|
|
|||||
|
Stock-based compensation
|
—
|
|
—
|
|
|
20,645
|
|
|
—
|
|
|
—
|
|
|
20,645
|
|
|||||
|
Distribution to noncontrolling interest
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,968
|
)
|
|
(7,968
|
)
|
|||||
|
Common shares issued in public offering, net of offering costs
|
9,488
|
|
94
|
|
|
649,979
|
|
|
—
|
|
|
—
|
|
|
650,073
|
|
|||||
|
Exercise of stock options and awards of restricted stock
|
421
|
|
5
|
|
|
4,866
|
|
|
—
|
|
|
—
|
|
|
4,871
|
|
|||||
|
Net income (loss)
|
—
|
|
—
|
|
|
—
|
|
|
(550,628
|
)
|
|
2,838
|
|
|
(547,790
|
)
|
|||||
|
Balance December 31, 2015
|
66,797
|
|
$
|
668
|
|
|
$
|
2,229,664
|
|
|
$
|
(354,360
|
)
|
|
$
|
233,001
|
|
|
$
|
2,108,973
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Cash flows from operating activities:
|
|
|
|
|
|
||||||
|
Net income (loss)
|
$
|
(547,790
|
)
|
|
$
|
195,971
|
|
|
$
|
54,587
|
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
|
Provision for (benefit from) deferred income taxes
|
(201,545
|
)
|
|
108,985
|
|
|
31,563
|
|
|||
|
Excess tax benefit from stock-based compensation
|
—
|
|
|
—
|
|
|
(749
|
)
|
|||
|
Impairment of oil and natural gas properties
|
814,798
|
|
|
—
|
|
|
—
|
|
|||
|
Asset retirement obligation accretion expense
|
833
|
|
|
467
|
|
|
201
|
|
|||
|
Depreciation, depletion, and amortization
|
217,697
|
|
|
170,005
|
|
|
66,597
|
|
|||
|
Amortization of debt issuance costs
|
2,601
|
|
|
2,125
|
|
|
1,018
|
|
|||
|
Change in fair value of derivative instruments
|
112,918
|
|
|
(117,109
|
)
|
|
(5,346
|
)
|
|||
|
Equity-based compensation expense
|
18,529
|
|
|
9,816
|
|
|
1,752
|
|
|||
|
(Gain) loss on sale of assets, net
|
668
|
|
|
1,396
|
|
|
(39
|
)
|
|||
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
||||||
|
Accounts receivable
|
8,998
|
|
|
(39,442
|
)
|
|
(19,973
|
)
|
|||
|
Accounts receivable-related party
|
2,149
|
|
|
(2,699
|
)
|
|
(532
|
)
|
|||
|
Restricted cash
|
—
|
|
|
(500
|
)
|
|
—
|
|
|||
|
Inventories
|
224
|
|
|
915
|
|
|
554
|
|
|||
|
Prepaid expenses and other
|
(1,310
|
)
|
|
(4,601
|
)
|
|
(271
|
)
|
|||
|
Accounts payable and accrued liabilities
|
802
|
|
|
6,829
|
|
|
20,588
|
|
|||
|
Accounts payable and accrued liabilities-related party
|
218
|
|
|
(17
|
)
|
|
(128
|
)
|
|||
|
Accrued interest
|
(255
|
)
|
|
3,473
|
|
|
—
|
|
|||
|
Revenues and royalties payable
|
(13,034
|
)
|
|
20,775
|
|
|
5,955
|
|
|||
|
Net cash provided by operating activities
|
416,501
|
|
|
356,389
|
|
|
155,777
|
|
|||
|
Cash flows from investing activities:
|
|
|
|
|
|
||||||
|
Additions to oil and natural gas properties
|
(419,241
|
)
|
|
(494,708
|
)
|
|
(278,809
|
)
|
|||
|
Additions to oil and natural gas properties-related party
|
(271
|
)
|
|
(3,631
|
)
|
|
(13,777
|
)
|
|||
|
Acquisition of Gulfport properties
|
—
|
|
|
—
|
|
|
(18,550
|
)
|
|||
|
Acquisition of royalty interests
|
(43,907
|
)
|
|
(57,689
|
)
|
|
(444,083
|
)
|
|||
|
Acquisition of leasehold interests
|
(437,455
|
)
|
|
(845,826
|
)
|
|
(177,343
|
)
|
|||
|
Pipeline and gas gathering assets
|
—
|
|
|
(1,509
|
)
|
|
(5,127
|
)
|
|||
|
Purchase of other property and equipment
|
(1,213
|
)
|
|
(44,213
|
)
|
|
(2,234
|
)
|
|||
|
Proceeds from sale of assets
|
9,739
|
|
|
56
|
|
|
72
|
|
|||
|
Equity investments
|
(2,702
|
)
|
|
(34,477
|
)
|
|
—
|
|
|||
|
Settlement of non-hedge derivative instruments
|
—
|
|
|
—
|
|
|
(289
|
)
|
|||
|
Net cash used in investing activities
|
(895,050
|
)
|
|
(1,481,997
|
)
|
|
(940,140
|
)
|
|||
|
Cash flows from financing activities:
|
|
|
|
|
|
||||||
|
Proceeds from borrowings on credit facility
|
425,001
|
|
|
509,400
|
|
|
59,000
|
|
|||
|
Repayment on credit facility
|
(603,001
|
)
|
|
(295,900
|
)
|
|
(49,000
|
)
|
|||
|
Proceeds from senior notes
|
—
|
|
|
—
|
|
|
450,000
|
|
|||
|
Debt issuance costs
|
(526
|
)
|
|
(3,469
|
)
|
|
(12,361
|
)
|
|||
|
Public offering costs
|
(586
|
)
|
|
(2,994
|
)
|
|
(1,009
|
)
|
|||
|
Proceeds from public offerings
|
650,688
|
|
|
928,432
|
|
|
322,680
|
|
|||
|
Exercise of stock options
|
4,873
|
|
|
7,081
|
|
|
3,501
|
|
|||
|
Excess tax benefits of stock-based compensation
|
—
|
|
|
—
|
|
|
749
|
|
|||
|
Distribution to non-controlling interest
|
(7,968
|
)
|
|
(2,314
|
)
|
|
—
|
|
|||
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Net cash provided by financing activities
|
468,481
|
|
|
1,140,236
|
|
|
773,560
|
|
|||
|
Net increase (decrease) in cash and cash equivalents
|
(10,068
|
)
|
|
14,628
|
|
|
(10,803
|
)
|
|||
|
Cash and cash equivalents at beginning of period
|
30,183
|
|
|
15,555
|
|
|
26,358
|
|
|||
|
Cash and cash equivalents at end of period
|
$
|
20,115
|
|
|
$
|
30,183
|
|
|
$
|
15,555
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
|
|
|
|
|
||||||
|
|
(In thousands)
|
||||||||||
|
Supplemental disclosure of cash flow information:
|
|
|
|
|
|
||||||
|
Interest paid, net of capitalized interest
|
$
|
38,758
|
|
|
$
|
31,621
|
|
|
$
|
404
|
|
|
Cash paid for income taxes
|
$
|
267
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Supplemental disclosure of non-cash transactions:
|
|
|
|
|
|
||||||
|
Asset retirement obligation incurred
|
$
|
594
|
|
|
$
|
703
|
|
|
$
|
226
|
|
|
Asset retirement obligation revisions in estimated liability
|
$
|
(69
|
)
|
|
$
|
588
|
|
|
$
|
—
|
|
|
Asset retirement obligation acquired
|
$
|
3,159
|
|
|
$
|
3,726
|
|
|
$
|
471
|
|
|
Change in accrued capital expenditures
|
$
|
(69,460
|
)
|
|
$
|
54,748
|
|
|
$
|
45,252
|
|
|
Capitalized stock-based compensation
|
$
|
6,043
|
|
|
$
|
4,437
|
|
|
$
|
972
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(In thousands)
|
||||||
|
Prepaid drilling liability
|
$
|
12,683
|
|
|
$
|
3,758
|
|
|
Interest payable
|
8,606
|
|
|
8,861
|
|
||
|
Lease operating expense payable
|
14,100
|
|
|
11,851
|
|
||
|
Taxes payable
|
518
|
|
|
9,952
|
|
||
|
Current portion of asset retirement obligations
|
193
|
|
|
39
|
|
||
|
Other
|
8,193
|
|
|
6,688
|
|
||
|
Total other accrued liabilities
|
$
|
44,293
|
|
|
$
|
41,149
|
|
|
|
(in thousands)
|
||
|
Joint interest receivables
|
$
|
42
|
|
|
Proved oil and natural gas properties
|
128,589
|
|
|
|
Unevaluated oil and natural gas properties
|
400,527
|
|
|
|
Total assets acquired
|
529,158
|
|
|
|
Accrued production and ad valorem taxes
|
358
|
|
|
|
Revenues payable
|
3,174
|
|
|
|
Asset retirement obligations
|
2,366
|
|
|
|
Total liabilities assumed
|
5,898
|
|
|
|
Total fair value of net assets
|
$
|
523,260
|
|
|
|
(in thousands)
|
||
|
Proved oil and natural gas properties
|
$
|
170,174
|
|
|
Unevaluated oil and natural gas properties
|
123,243
|
|
|
|
Total assets acquired
|
293,417
|
|
|
|
Asset retirement obligations
|
1,258
|
|
|
|
Total liabilities assumed
|
1,258
|
|
|
|
Total fair value of net assets
|
$
|
292,159
|
|
|
|
Pro Forma
|
||||||
|
|
(Unaudited)
|
||||||
|
|
Year Ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
|
|
|
||||
|
|
(in thousands)
|
||||||
|
Revenues
|
$
|
541,103
|
|
|
$
|
315,736
|
|
|
Income from operations
|
224,382
|
|
|
146,429
|
|
||
|
Net income
|
201,257
|
|
|
86,277
|
|
||
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in thousands)
|
||||||
|
Oil and natural gas properties:
|
|
|
|
||||
|
Subject to depletion
|
$
|
2,848,557
|
|
|
$
|
2,345,077
|
|
|
Not subject to depletion-acquisition costs
|
|
|
|
||||
|
Incurred in 2015
|
433,769
|
|
|
—
|
|
||
|
Incurred in 2014
|
543,399
|
|
|
576,802
|
|
||
|
Incurred in 2013
|
68,351
|
|
|
130,474
|
|
||
|
Incurred in 2012
|
61,297
|
|
|
65,480
|
|
||
|
Incurred in 2011
|
—
|
|
|
764
|
|
||
|
Total not subject to depletion
|
1,106,816
|
|
|
773,520
|
|
||
|
Gross oil and natural gas properties
|
3,955,373
|
|
|
3,118,597
|
|
||
|
Accumulated depletion
|
(512,144
|
)
|
|
(296,317
|
)
|
||
|
Accumulated impairment
|
(897,962
|
)
|
|
(83,164
|
)
|
||
|
Oil and natural gas properties, net
|
2,545,267
|
|
|
2,739,116
|
|
||
|
Pipeline and gas gathering assets, net
|
7,174
|
|
|
7,174
|
|
||
|
Other property and equipment, net
|
48,621
|
|
|
48,180
|
|
||
|
Accumulated depreciation
|
(3,437
|
)
|
|
(2,663
|
)
|
||
|
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment
|
$
|
2,597,625
|
|
|
$
|
2,791,807
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
Asset retirement obligation, beginning of period
|
$
|
8,486
|
|
|
$
|
3,029
|
|
|
$
|
2,145
|
|
|
Additional liability incurred
|
594
|
|
|
703
|
|
|
226
|
|
|||
|
Liabilities acquired
|
3,159
|
|
|
3,726
|
|
|
471
|
|
|||
|
Liabilities settled
|
(292
|
)
|
|
(27
|
)
|
|
(14
|
)
|
|||
|
Accretion expense
|
833
|
|
|
467
|
|
|
201
|
|
|||
|
Revisions in estimated liabilities
|
(69
|
)
|
|
588
|
|
|
—
|
|
|||
|
Asset retirement obligation, end of period
|
12,711
|
|
|
8,486
|
|
|
3,029
|
|
|||
|
Less current portion
|
193
|
|
|
39
|
|
|
40
|
|
|||
|
Asset retirement obligations - long-term
|
$
|
12,518
|
|
|
$
|
8,447
|
|
|
$
|
2,989
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in thousands)
|
||||||
|
7.625 % Senior Notes due 2021
|
$
|
450,000
|
|
|
$
|
450,000
|
|
|
Revolving credit facility
|
$
|
11,000
|
|
|
$
|
223,500
|
|
|
Partnership revolving credit facility
|
34,500
|
|
|
—
|
|
||
|
Total long-term debt
|
$
|
495,500
|
|
|
$
|
673,500
|
|
|
Financial Covenant
|
Required Ratio
|
|
Ratio of total debt to EBITDAX
|
Not greater than 4.0 to 1.0
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
|
Financial Covenant
|
Required Ratio
|
|
Ratio of total debt to EBITDAX
|
Not greater than 4.0 to 1.0
|
|
Ratio of current assets to liabilities, as defined in the credit agreement
|
Not less than 1.0 to 1.0
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
Interest expense
|
$
|
40,221
|
|
|
$
|
36,669
|
|
|
$
|
10,322
|
|
|
Less capitalized interest
|
—
|
|
|
(5,275
|
)
|
|
(3,951
|
)
|
|||
|
Other fees and expenses
|
1,292
|
|
|
3,121
|
|
|
1,688
|
|
|||
|
Total interest expense
|
41,513
|
|
|
34,515
|
|
|
8,059
|
|
|||
|
|
2015
|
|||||||||
|
|
Income
|
|
Shares
|
|
Per Share
|
|||||
|
|
|
|
|
|
|
|||||
|
|
(in thousands, except per share amounts)
|
|||||||||
|
Basic:
|
|
|
|
|
|
|||||
|
Net income attributable to common stock
|
$
|
(550,628
|
)
|
|
63,019
|
|
|
$
|
(8.74
|
)
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|||||
|
Dilutive effect of potential common shares issuable
|
$
|
—
|
|
|
—
|
|
|
|
||
|
Diluted:
|
|
|
|
|
|
|||||
|
Net income attributable to common stock
|
$
|
(550,628
|
)
|
|
63,019
|
|
|
$
|
(8.74
|
)
|
|
|
2014
|
|||||||||
|
|
Income
|
|
Shares
|
|
Per Share
|
|||||
|
|
|
|
|
|
|
|||||
|
|
(in thousands, except per share amounts)
|
|||||||||
|
Basic:
|
|
|
|
|
|
|||||
|
Net income attributable to common stock
|
$
|
193,755
|
|
|
52,826
|
|
|
$
|
3.67
|
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|||||
|
Dilutive effect of potential common shares issuable
|
$
|
—
|
|
|
471
|
|
|
|
||
|
Diluted:
|
|
|
|
|
|
|||||
|
Net income attributable to common stock
|
$
|
193,755
|
|
|
53,297
|
|
|
$
|
3.64
|
|
|
|
2013
|
|||||||||
|
|
Income
|
|
Shares
|
|
Per Share
|
|||||
|
|
|
|
|
|
|
|||||
|
|
(in thousands, except per share amounts)
|
|||||||||
|
Basic:
|
|
|
|
|
|
|||||
|
Net income attributable to common stock
|
$
|
54,587
|
|
|
42,015
|
|
|
$
|
1.30
|
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|||||
|
Dilutive effect of potential common shares issuable
|
$
|
—
|
|
|
240
|
|
|
|
||
|
Diluted:
|
|
|
|
|
|
|||||
|
Net income attributable to common stock
|
$
|
54,587
|
|
|
42,255
|
|
|
$
|
1.29
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
General and administrative expenses
|
$
|
18,529
|
|
|
$
|
9,816
|
|
|
$
|
1,752
|
|
|
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties
|
6,043
|
|
|
4,437
|
|
|
972
|
|
|||
|
Related income tax benefit
|
—
|
|
|
—
|
|
|
704
|
|
|||
|
|
2013
|
||
|
Grant-date fair value
|
$
|
6.51
|
|
|
Expected volatility
|
36.9
|
%
|
|
|
Expected dividend yield
|
0.0
|
%
|
|
|
Expected term (in years)
|
3.8
|
|
|
|
Risk-free rate
|
0.57
|
%
|
|
|
|
|
|
Weighted Average
|
|
|
|||||||
|
|
|
|
Exercise
|
|
Remaining
|
|
Intrinsic
|
|||||
|
|
Options
|
|
Price
|
|
Term
|
|
Value
|
|||||
|
|
|
|
|
|
(in years)
|
|
(in thousands)
|
|||||
|
Outstanding at December 31, 2014
|
313,105
|
|
|
$
|
18.29
|
|
|
|
|
|
||
|
Exercised
|
(273,605
|
)
|
|
$
|
17.80
|
|
|
|
|
|
||
|
Outstanding at December 31, 2015
|
39,500
|
|
|
$
|
21.66
|
|
|
1.83
|
|
$
|
1,787
|
|
|
Vested and Expected to vest at December 31, 2015
|
39,500
|
|
|
$
|
21.66
|
|
|
1.83
|
|
$
|
1,787
|
|
|
Exercisable at December 31, 2015
|
8,000
|
|
|
$
|
17.50
|
|
|
0.78
|
|
$
|
395
|
|
|
|
Restricted Stock
Awards & Units |
|
Weighted Average Grant-Date
Fair Value |
|||
|
Unvested at December 31, 2014
|
167,291
|
|
|
$
|
49.99
|
|
|
Granted
|
138,534
|
|
|
$
|
68.54
|
|
|
Vested
|
(143,956
|
)
|
|
$
|
42.58
|
|
|
Forfeited
|
(2,110
|
)
|
|
$
|
74.14
|
|
|
Unvested at December 31, 2015
|
159,759
|
|
|
$
|
64.66
|
|
|
|
2015
|
|
2014
|
||||
|
Grant-date fair value
|
$
|
137.14
|
|
|
$
|
125.63
|
|
|
Risk-free rate
|
0.49
|
%
|
|
0.30
|
%
|
||
|
Company volatility
|
43.36
|
%
|
|
39.60
|
%
|
||
|
|
Performance Restricted Stock Units
|
|
Weighted Average Grant-Date Fair Value
|
|||
|
Unvested at December 31, 2014
|
79,150
|
|
|
$
|
125.63
|
|
|
Granted
|
90,249
|
|
|
$
|
137.14
|
|
|
Vested
|
(79,150
|
)
|
|
$
|
125.63
|
|
|
Unvested at December 31, 2015
(1)
|
90,249
|
|
|
$
|
137.14
|
|
|
(1)
|
A maximum of
180,498
units could be awarded based upon the Company’s final TSR ranking.
|
|
|
2014
|
||
|
Grant-date fair value
|
$
|
4.24
|
|
|
Expected volatility
|
36.0
|
%
|
|
|
Expected dividend yield
|
5.9
|
%
|
|
|
Expected term (in years)
|
3.0
|
|
|
|
Risk-free rate
|
0.99
|
%
|
|
|
|
|
|
Weighted Average
|
|
|
|||||||
|
|
Unit Options
|
|
Exercise Price
|
|
Remaining Term
|
|
Intrinsic Value
|
|||||
|
|
|
|
|
|
(in years)
|
|
(in thousands)
|
|||||
|
Outstanding at December 31, 2014
|
2,500,000
|
|
|
$
|
26.00
|
|
|
|
|
|
||
|
Granted
|
—
|
|
|
$
|
—
|
|
|
|
|
|
||
|
Outstanding at December 31, 2015
|
2,500,000
|
|
|
$
|
—
|
|
|
1.50
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Vested and Expected to vest at December 31, 2015
|
2,500,000
|
|
|
$
|
—
|
|
|
1.50
|
|
$
|
—
|
|
|
Exercisable at December 31, 2015
|
—
|
|
|
$
|
—
|
|
|
0.00
|
|
$
|
—
|
|
|
|
Phantom Units
|
|
Weighted Average Grant-Date
Fair Value |
|||
|
Unvested at December 31, 2014
|
17,776
|
|
|
$
|
19.51
|
|
|
Granted
|
24,690
|
|
|
$
|
15.48
|
|
|
Vested
|
(17,118
|
)
|
|
$
|
17.57
|
|
|
Unvested at December 31, 2015
|
25,348
|
|
|
$
|
16.89
|
|
|
Date of Amendment
|
Reason for Amendment
|
Current Monthly Base Rent
|
New Monthly Base Rent or Rent for Additional Space
|
Approx. Annual Increase of Monthly Base Rent
|
|
2
nd
and 3
rd
quarters 2013
(1)
|
Lease additional space
|
$13,000
|
$15,000
|
N/A
|
|
2
nd
quarter 2014
|
Lease additional space
|
$25,000
|
$27,000
|
N/A
|
|
4
th
quarter 2014
(2)
|
Lease additional space
|
$27,000
|
$53,000
|
4%
|
|
November 2014
(3)(4)
|
Extend the term
|
N/A
|
N/A
|
N/A
|
|
April 2015
|
Lease additional space
|
N/A
|
$23,000
|
N/A
|
|
June 2015
|
Lease additional space
|
N/A
|
$22,000
|
2%
|
|
(1)
|
The monthly rent will increase further to
$25,000
beginning on October 1, 2013.
|
|
(2)
|
The monthly rent will continue to increase approximately
4%
annually on June 1 of each year during the remainder of the lease term.
|
|
(3)
|
The lease was amended to extend the term of the lease for an additional
10
-year period.
|
|
(4)
|
Upon commencement of the extension in June 2016, the monthly base rent will increase to
$94,000
, with an increase of approximately
2%
annually.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Current income tax provision (benefit):
|
|
|
|
|
|
||||||
|
Federal
|
$
|
(33
|
)
|
|
$
|
—
|
|
|
$
|
191
|
|
|
State
|
268
|
|
|
—
|
|
|
—
|
|
|||
|
Total current income tax provision
|
235
|
|
|
—
|
|
|
191
|
|
|||
|
Deferred income tax provision (benefit):
|
|
|
|
|
|
||||||
|
Federal
|
(198,729
|
)
|
|
106,107
|
|
|
30,768
|
|
|||
|
State
|
(2,816
|
)
|
|
2,878
|
|
|
795
|
|
|||
|
Total deferred income tax provision (benefit)
|
(201,545
|
)
|
|
108,985
|
|
|
31,563
|
|
|||
|
Total provision for (benefit from) income taxes
|
$
|
(201,310
|
)
|
|
$
|
108,985
|
|
|
$
|
31,754
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Income tax expense (benefit) at the federal statutory rate (35%)
|
$
|
(263,179
|
)
|
|
$
|
105,959
|
|
|
$
|
30,231
|
|
|
Income tax expense (benefit) relating to change in tax rate
|
(1,145
|
)
|
|
—
|
|
|
—
|
|
|||
|
State income tax expense (benefit), net of federal tax effect
|
(2,548
|
)
|
|
2,878
|
|
|
517
|
|
|||
|
Non-deductible expenses and other
|
4,506
|
|
|
148
|
|
|
1,006
|
|
|||
|
Change in valuation allowance
|
61,056
|
|
|
—
|
|
|
—
|
|
|||
|
Provision for (benefit from) income taxes
|
$
|
(201,310
|
)
|
|
$
|
108,985
|
|
|
$
|
31,754
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(In thousands)
|
||||||
|
Current:
|
|
|
|
||||
|
Deferred tax assets
|
|
|
|
||||
|
Derivative instruments
|
$
|
—
|
|
|
$
|
—
|
|
|
Other
|
2,658
|
|
|
1,950
|
|
||
|
Current deferred tax assets
|
2,658
|
|
|
1,950
|
|
||
|
Valuation allowance
|
(1,018
|
)
|
|
—
|
|
||
|
Current deferred tax assets, net of valuation allowance
|
1,640
|
|
|
1,950
|
|
||
|
Deferred tax liabilities
|
|
|
|
||||
|
Derivative instruments
|
1,640
|
|
|
41,903
|
|
||
|
Total current deferred tax liabilities
|
1,640
|
|
|
41,903
|
|
||
|
Net current deferred tax assets
|
—
|
|
|
(39,953
|
)
|
||
|
Noncurrent:
|
|
|
|
||||
|
Deferred tax assets
|
|
|
|
||||
|
Net operating loss carryforwards (subject to 20 year expiration)
|
82,635
|
|
|
49,627
|
|
||
|
Stock based compensation
|
3,873
|
|
|
2,520
|
|
||
|
Alternative minimum tax credit carryforward
|
—
|
|
|
33
|
|
||
|
Other
|
4,533
|
|
|
—
|
|
||
|
Noncurrent deferred tax assets
|
91,041
|
|
|
52,180
|
|
||
|
Valuation allowance
|
(60,038
|
)
|
|
—
|
|
||
|
Noncurrent deferred tax assets, net of valuation allowance
|
31,003
|
|
|
52,180
|
|
||
|
Deferred tax liabilities
|
|
|
|
||||
|
Oil and natural gas properties and equipment
|
31,003
|
|
|
213,772
|
|
||
|
Other
|
—
|
|
|
—
|
|
||
|
Total noncurrent deferred tax liabilities
|
31,003
|
|
|
213,772
|
|
||
|
Net noncurrent deferred tax liabilities
|
—
|
|
|
161,592
|
|
||
|
Net deferred tax liabilities
|
$
|
—
|
|
|
$
|
201,545
|
|
|
Crude Oil—Inter–Continental Exchange Brent Fixed Price Swap
|
|
|
|
||
|
Production Period
|
Volume (Bbls)
|
|
Fixed Swap Price
|
||
|
January - February 2016
|
91,000
|
|
|
88.72
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in thousands)
|
||||||
|
Gross amounts of recognized assets
|
$
|
4,623
|
|
|
$
|
117,541
|
|
|
Gross amounts offset in the Consolidated Balance Sheet
|
—
|
|
|
—
|
|
||
|
Net amounts of assets presented in the Consolidated Balance Sheet
|
$
|
4,623
|
|
|
$
|
117,541
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in thousands)
|
||||||
|
Current Assets: Derivative instruments
|
$
|
4,623
|
|
|
$
|
115,607
|
|
|
Noncurrent Assets: Derivative instruments
|
—
|
|
|
1,934
|
|
||
|
Total Assets
|
$
|
4,623
|
|
|
$
|
117,541
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
Change in fair value of open non-hedge derivative instruments
|
$
|
(112,918
|
)
|
|
$
|
117,109
|
|
|
$
|
5,346
|
|
|
Gain (loss) on settlement of non-hedge derivative instruments
|
144,869
|
|
|
10,430
|
|
|
(7,218
|
)
|
|||
|
Gain (loss) on derivative instruments
|
$
|
31,951
|
|
|
$
|
127,539
|
|
|
$
|
(1,872
|
)
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in thousands)
|
||||||
|
Fixed price swaps:
|
|
|
|
||||
|
Quoted prices in active markets level 1
|
$
|
—
|
|
|
$
|
—
|
|
|
Significant other observable inputs level 2
|
4,623
|
|
|
117,541
|
|
||
|
Significant unobservable inputs level 3
|
—
|
|
|
—
|
|
||
|
Total
|
$
|
4,623
|
|
|
$
|
117,541
|
|
|
|
December 31, 2015
|
|
December 31, 2014
|
||||||||||||
|
|
Carrying
|
|
|
|
Carrying
|
|
|
||||||||
|
|
Amount
|
|
Fair Value
|
|
Amount
|
|
Fair Value
|
||||||||
|
|
(in thousands)
|
||||||||||||||
|
Debt:
|
|
|
|
|
|
|
|
||||||||
|
Revolving credit facility
|
$
|
11,000
|
|
|
$
|
11,000
|
|
|
$
|
223,500
|
|
|
$
|
223,500
|
|
|
7.625% Senior Notes due 2021
|
450,000
|
|
|
450,000
|
|
|
450,000
|
|
|
440,438
|
|
||||
|
Partnership revolving credit facility
|
34,500
|
|
|
34,500
|
|
|
—
|
|
|
—
|
|
||||
|
Year Ending December 31,
|
Drilling Rig Commitments
|
|
Office and Equipment Leases
|
||||
|
|
(in thousands)
|
||||||
|
2016
|
$
|
29,536
|
|
|
$
|
1,935
|
|
|
2017
|
19,893
|
|
|
2,053
|
|
||
|
2018
|
16,866
|
|
|
1,973
|
|
||
|
2019
|
589
|
|
|
1,839
|
|
||
|
2020
|
—
|
|
|
1,659
|
|
||
|
Thereafter
|
—
|
|
|
9,583
|
|
||
|
Total
|
$
|
66,884
|
|
|
$
|
19,042
|
|
|
|
Year ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in thousands)
|
||||||||||
|
Rent Expense
|
$
|
1,449
|
|
|
$
|
852
|
|
|
$
|
571
|
|
|
Condensed Consolidated Balance Sheet
|
|||||||||||||||||||
|
December 31, 2015
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Current assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Cash and cash equivalents
|
$
|
148
|
|
|
$
|
19,428
|
|
|
$
|
539
|
|
|
$
|
—
|
|
|
$
|
20,115
|
|
|
Restricted cash
|
—
|
|
|
—
|
|
|
500
|
|
|
—
|
|
|
500
|
|
|||||
|
Accounts receivable
|
—
|
|
|
67,942
|
|
|
9,369
|
|
|
2
|
|
|
77,313
|
|
|||||
|
Accounts receivable - related party
|
—
|
|
|
1,591
|
|
|
—
|
|
|
—
|
|
|
1,591
|
|
|||||
|
Intercompany receivable
|
2,246,846
|
|
|
205,915
|
|
|
—
|
|
|
(2,452,761
|
)
|
|
—
|
|
|||||
|
Inventories
|
—
|
|
|
1,728
|
|
|
—
|
|
|
—
|
|
|
1,728
|
|
|||||
|
Other current assets
|
450
|
|
|
6,572
|
|
|
476
|
|
|
—
|
|
|
7,498
|
|
|||||
|
Total current assets
|
2,247,444
|
|
|
303,176
|
|
|
10,884
|
|
|
(2,452,759
|
)
|
|
108,745
|
|
|||||
|
Property and equipment
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Oil and natural gas properties, at cost, based on the full cost method of accounting
|
—
|
|
|
3,400,381
|
|
|
554,992
|
|
|
—
|
|
|
3,955,373
|
|
|||||
|
Pipeline and gas gathering assets
|
—
|
|
|
7,174
|
|
|
—
|
|
|
—
|
|
|
7,174
|
|
|||||
|
Other property and equipment
|
—
|
|
|
48,621
|
|
|
—
|
|
|
—
|
|
|
48,621
|
|
|||||
|
Accumulated depletion, depreciation, amortization and impairment
|
—
|
|
|
(1,347,296
|
)
|
|
(71,659
|
)
|
|
5,412
|
|
|
(1,413,543
|
)
|
|||||
|
Net property and equipment
|
—
|
|
|
2,108,880
|
|
|
483,333
|
|
|
5,412
|
|
|
2,597,625
|
|
|||||
|
Investment in subsidiaries
|
79,417
|
|
|
—
|
|
|
—
|
|
|
(79,417
|
)
|
|
—
|
|
|||||
|
Other assets
|
7,795
|
|
|
8,733
|
|
|
35,514
|
|
|
—
|
|
|
52,042
|
|
|||||
|
Total assets
|
$
|
2,334,656
|
|
|
$
|
2,420,789
|
|
|
$
|
529,731
|
|
|
$
|
(2,526,764
|
)
|
|
$
|
2,758,412
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Accounts payable-trade
|
$
|
—
|
|
|
$
|
20,007
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
20,008
|
|
|
Accounts payable-related party
|
1
|
|
|
212
|
|
|
4
|
|
|
—
|
|
|
217
|
|
|||||
|
Intercompany payable
|
—
|
|
|
2,452,759
|
|
|
—
|
|
|
(2,452,759
|
)
|
|
—
|
|
|||||
|
Other current liabilities
|
8,683
|
|
|
112,431
|
|
|
82
|
|
|
—
|
|
|
121,196
|
|
|||||
|
Total current liabilities
|
8,684
|
|
|
2,585,409
|
|
|
87
|
|
|
(2,452,759
|
)
|
|
141,421
|
|
|||||
|
Long-term debt
|
450,000
|
|
|
11,000
|
|
|
34,500
|
|
|
—
|
|
|
495,500
|
|
|||||
|
Asset retirement obligations
|
—
|
|
|
12,518
|
|
|
—
|
|
|
—
|
|
|
12,518
|
|
|||||
|
Total liabilities
|
458,684
|
|
|
2,608,927
|
|
|
34,587
|
|
|
(2,452,759
|
)
|
|
649,439
|
|
|||||
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Stockholders’ equity:
|
1,875,972
|
|
|
(188,138
|
)
|
|
495,144
|
|
|
(307,006
|
)
|
|
1,875,972
|
|
|||||
|
Noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
233,001
|
|
|
233,001
|
|
|||||
|
Total equity
|
1,875,972
|
|
|
(188,138
|
)
|
|
495,144
|
|
|
(74,005
|
)
|
|
2,108,973
|
|
|||||
|
Total liabilities and equity
|
$
|
2,334,656
|
|
|
$
|
2,420,789
|
|
|
$
|
529,731
|
|
|
$
|
(2,526,764
|
)
|
|
$
|
2,758,412
|
|
|
Condensed Consolidated Balance Sheet
|
|||||||||||||||||||
|
December 31, 2014
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Assets
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Current assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Cash and cash equivalents
|
$
|
6
|
|
|
$
|
15,067
|
|
|
$
|
15,110
|
|
|
$
|
—
|
|
|
$
|
30,183
|
|
|
Restricted cash
|
—
|
|
|
—
|
|
|
500
|
|
|
—
|
|
|
500
|
|
|||||
|
Accounts receivable
|
—
|
|
|
85,752
|
|
|
8,239
|
|
|
2
|
|
|
93,993
|
|
|||||
|
Accounts receivable - related party
|
—
|
|
|
4,001
|
|
|
—
|
|
|
—
|
|
|
4,001
|
|
|||||
|
Intercompany receivable
|
1,658,215
|
|
|
2,167,434
|
|
|
—
|
|
|
(3,825,649
|
)
|
|
—
|
|
|||||
|
Inventories
|
—
|
|
|
2,827
|
|
|
—
|
|
|
—
|
|
|
2,827
|
|
|||||
|
Other current assets
|
562
|
|
|
119,392
|
|
|
253
|
|
|
—
|
|
|
120,207
|
|
|||||
|
Total current assets
|
1,658,783
|
|
|
2,394,473
|
|
|
24,102
|
|
|
(3,825,647
|
)
|
|
251,711
|
|
|||||
|
Property and equipment
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Oil and natural gas properties, at cost, based on the full cost method of accounting
|
—
|
|
|
2,607,513
|
|
|
511,084
|
|
|
—
|
|
|
3,118,597
|
|
|||||
|
Pipeline and gas gathering assets
|
—
|
|
|
7,174
|
|
|
—
|
|
|
—
|
|
|
7,174
|
|
|||||
|
Other property and equipment
|
—
|
|
|
48,180
|
|
|
—
|
|
|
—
|
|
|
48,180
|
|
|||||
|
Accumulated depletion, depreciation, amortization and impairment
|
—
|
|
|
(351,200
|
)
|
|
(32,799
|
)
|
|
1,855
|
|
|
(382,144
|
)
|
|||||
|
Net property and equipment
|
—
|
|
|
2,311,667
|
|
|
478,285
|
|
|
1,855
|
|
|
2,791,807
|
|
|||||
|
Investment in subsidiaries
|
839,217
|
|
|
—
|
|
|
—
|
|
|
(839,217
|
)
|
|
—
|
|
|||||
|
Other assets
|
9,155
|
|
|
7,793
|
|
|
35,015
|
|
|
—
|
|
|
51,963
|
|
|||||
|
Total assets
|
$
|
2,507,155
|
|
|
$
|
4,713,933
|
|
|
$
|
537,402
|
|
|
$
|
(4,663,009
|
)
|
|
$
|
3,095,481
|
|
|
Liabilities and Stockholders’ Equity
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Accounts payable-trade
|
$
|
—
|
|
|
$
|
26,224
|
|
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
26,230
|
|
|
Intercompany payable
|
95,362
|
|
|
3,730,287
|
|
|
—
|
|
|
(3,825,649
|
)
|
|
—
|
|
|||||
|
Other current liabilities
|
49,190
|
|
|
189,264
|
|
|
2,045
|
|
|
—
|
|
|
240,499
|
|
|||||
|
Total current liabilities
|
144,552
|
|
|
3,945,775
|
|
|
2,051
|
|
|
(3,825,649
|
)
|
|
266,729
|
|
|||||
|
Long-term debt
|
450,000
|
|
|
223,500
|
|
|
—
|
|
|
—
|
|
|
673,500
|
|
|||||
|
Asset retirement obligations
|
—
|
|
|
8,447
|
|
|
—
|
|
|
—
|
|
|
8,447
|
|
|||||
|
Deferred income taxes
|
161,592
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
161,592
|
|
|||||
|
Total liabilities
|
756,144
|
|
|
4,177,722
|
|
|
2,051
|
|
|
(3,825,649
|
)
|
|
1,110,268
|
|
|||||
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Stockholders’ equity:
|
1,751,011
|
|
|
536,211
|
|
|
535,351
|
|
|
(1,071,562
|
)
|
|
1,751,011
|
|
|||||
|
Noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
234,202
|
|
|
234,202
|
|
|||||
|
Total equity
|
1,751,011
|
|
|
536,211
|
|
|
535,351
|
|
|
(837,360
|
)
|
|
1,985,213
|
|
|||||
|
Total liabilities and equity
|
$
|
2,507,155
|
|
|
$
|
4,713,933
|
|
|
$
|
537,402
|
|
|
$
|
(4,663,009
|
)
|
|
$
|
3,095,481
|
|
|
Condensed Consolidated Statement of Operations
|
|||||||||||||||||||
|
Year Ended December 31, 2015
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Oil sales
|
$
|
—
|
|
|
$
|
336,106
|
|
|
$
|
—
|
|
|
$
|
69,609
|
|
|
$
|
405,715
|
|
|
Natural gas sales
|
—
|
|
|
16,932
|
|
|
—
|
|
|
2,660
|
|
|
19,592
|
|
|||||
|
Natural gas liquid sales
|
—
|
|
|
18,836
|
|
|
—
|
|
|
2,590
|
|
|
21,426
|
|
|||||
|
Royalty income
|
—
|
|
|
—
|
|
|
74,859
|
|
|
(74,859
|
)
|
|
—
|
|
|||||
|
Total revenues
|
—
|
|
|
371,874
|
|
|
74,859
|
|
|
—
|
|
|
446,733
|
|
|||||
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Lease operating expenses
|
—
|
|
|
82,625
|
|
|
—
|
|
|
—
|
|
|
82,625
|
|
|||||
|
Production and ad valorem taxes
|
—
|
|
|
27,459
|
|
|
5,531
|
|
|
—
|
|
|
32,990
|
|
|||||
|
Gathering and transportation
|
—
|
|
|
5,832
|
|
|
259
|
|
|
—
|
|
|
6,091
|
|
|||||
|
Depreciation, depletion and amortization
|
—
|
|
|
182,395
|
|
|
35,436
|
|
|
(134
|
)
|
|
217,697
|
|
|||||
|
Impairment of oil and natural gas properties
|
—
|
|
|
814,798
|
|
|
3,423
|
|
|
(3,423
|
)
|
|
814,798
|
|
|||||
|
General and administrative expenses
|
17,077
|
|
|
9,056
|
|
|
5,835
|
|
|
—
|
|
|
31,968
|
|
|||||
|
Asset retirement obligation accretion expense
|
—
|
|
|
833
|
|
|
—
|
|
|
—
|
|
|
833
|
|
|||||
|
Total costs and expenses
|
17,077
|
|
|
1,122,998
|
|
|
50,484
|
|
|
(3,557
|
)
|
|
1,187,002
|
|
|||||
|
Income (loss) from operations
|
(17,077
|
)
|
|
(751,124
|
)
|
|
24,375
|
|
|
3,557
|
|
|
(740,269
|
)
|
|||||
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Interest expense
|
(35,651
|
)
|
|
(4,749
|
)
|
|
(1,110
|
)
|
|
—
|
|
|
(41,510
|
)
|
|||||
|
Other income
|
1
|
|
|
(588
|
)
|
|
1,154
|
|
|
—
|
|
|
567
|
|
|||||
|
Other income - intercompany
|
—
|
|
|
161
|
|
|
—
|
|
|
—
|
|
|
161
|
|
|||||
|
Gain (loss) on derivative instruments, net
|
—
|
|
|
31,951
|
|
|
—
|
|
|
—
|
|
|
31,951
|
|
|||||
|
Total other income (expense), net
|
(35,650
|
)
|
|
26,775
|
|
|
44
|
|
|
—
|
|
|
(8,831
|
)
|
|||||
|
Income (loss) before income taxes
|
(52,727
|
)
|
|
(724,349
|
)
|
|
24,419
|
|
|
3,557
|
|
|
(749,100
|
)
|
|||||
|
Benefit from income taxes
|
(201,310
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(201,310
|
)
|
|||||
|
Net income (loss)
|
148,583
|
|
|
(724,349
|
)
|
|
24,419
|
|
|
3,557
|
|
|
(547,790
|
)
|
|||||
|
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
2,838
|
|
|
2,838
|
|
|||||
|
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
148,583
|
|
|
$
|
(724,349
|
)
|
|
$
|
24,419
|
|
|
$
|
719
|
|
|
$
|
(550,628
|
)
|
|
Condensed Consolidated Statement of Operations
|
|||||||||||||||||||
|
Year Ended December 31, 2014
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Oil sales
|
$
|
—
|
|
|
$
|
377,712
|
|
|
$
|
—
|
|
|
$
|
71,532
|
|
|
$
|
449,244
|
|
|
Natural gas sales
|
—
|
|
|
15,240
|
|
|
—
|
|
|
2,788
|
|
|
18,028
|
|
|||||
|
Natural gas liquid sales
|
—
|
|
|
24,545
|
|
|
—
|
|
|
3,901
|
|
|
28,446
|
|
|||||
|
Royalty income
|
—
|
|
|
—
|
|
|
77,767
|
|
|
(77,767
|
)
|
|
—
|
|
|||||
|
Total revenues
|
—
|
|
|
417,497
|
|
|
77,767
|
|
|
454
|
|
|
495,718
|
|
|||||
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Lease operating expenses
|
—
|
|
|
55,384
|
|
|
—
|
|
|
—
|
|
|
55,384
|
|
|||||
|
Production and ad valorem taxes
|
—
|
|
|
27,242
|
|
|
5,377
|
|
|
19
|
|
|
32,638
|
|
|||||
|
Gathering and transportation
|
—
|
|
|
3,294
|
|
|
—
|
|
|
(6
|
)
|
|
3,288
|
|
|||||
|
Depreciation, depletion and amortization
|
—
|
|
|
143,477
|
|
|
27,601
|
|
|
(1,073
|
)
|
|
170,005
|
|
|||||
|
General and administrative expenses
|
10,879
|
|
|
7,189
|
|
|
4,372
|
|
|
(1,174
|
)
|
|
21,266
|
|
|||||
|
Asset retirement obligation accretion expense
|
—
|
|
|
467
|
|
|
—
|
|
|
—
|
|
|
467
|
|
|||||
|
Total costs and expenses
|
10,879
|
|
|
237,053
|
|
|
37,350
|
|
|
(2,234
|
)
|
|
283,048
|
|
|||||
|
Income (loss) from operations
|
(10,879
|
)
|
|
180,444
|
|
|
40,417
|
|
|
2,688
|
|
|
212,670
|
|
|||||
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Interest income - intercompany
|
10,755
|
|
|
—
|
|
|
—
|
|
|
(10,755
|
)
|
|
—
|
|
|||||
|
Interest expense
|
(30,281
|
)
|
|
(3,746
|
)
|
|
(487
|
)
|
|
—
|
|
|
(34,514
|
)
|
|||||
|
Interest expense - intercompany
|
—
|
|
|
—
|
|
|
(10,755
|
)
|
|
10,755
|
|
|
—
|
|
|||||
|
Other income
|
6
|
|
|
91
|
|
|
459
|
|
|
—
|
|
|
556
|
|
|||||
|
Other income - intercompany
|
—
|
|
|
1,027
|
|
|
—
|
|
|
(906
|
)
|
|
121
|
|
|||||
|
Other expense
|
—
|
|
|
(1,416
|
)
|
|
—
|
|
|
—
|
|
|
(1,416
|
)
|
|||||
|
Loss on derivative instruments, net
|
—
|
|
|
127,539
|
|
|
—
|
|
|
—
|
|
|
127,539
|
|
|||||
|
Total other income (expense), net
|
(19,520
|
)
|
|
123,495
|
|
|
(10,783
|
)
|
|
(906
|
)
|
|
92,286
|
|
|||||
|
Income before income taxes
|
(30,399
|
)
|
|
303,939
|
|
|
29,634
|
|
|
1,782
|
|
|
304,956
|
|
|||||
|
Provision for income taxes
|
108,985
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
108,985
|
|
|||||
|
Net income (loss)
|
$
|
(139,384
|
)
|
|
$
|
303,939
|
|
|
$
|
29,634
|
|
|
$
|
1,782
|
|
|
$
|
195,971
|
|
|
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
2,216
|
|
|
2,216
|
|
|||||
|
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
(139,384
|
)
|
|
$
|
303,939
|
|
|
$
|
29,634
|
|
|
$
|
(434
|
)
|
|
$
|
193,755
|
|
|
Condensed Consolidated Statement of Operations
|
|||||||||||||||||||
|
Year Ended December 31, 2013
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Oil sales
|
$
|
—
|
|
|
$
|
174,868
|
|
|
$
|
—
|
|
|
$
|
13,885
|
|
|
$
|
188,753
|
|
|
Natural gas sales
|
—
|
|
|
5,852
|
|
|
—
|
|
|
397
|
|
|
6,249
|
|
|||||
|
Natural gas liquid sales
|
—
|
|
|
12,295
|
|
|
—
|
|
|
705
|
|
|
13,000
|
|
|||||
|
Royalty income
|
—
|
|
|
—
|
|
|
14,987
|
|
|
(14,987
|
)
|
|
—
|
|
|||||
|
Total revenues
|
—
|
|
|
193,015
|
|
|
14,987
|
|
|
—
|
|
|
208,002
|
|
|||||
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Lease operating expenses
|
—
|
|
|
21,157
|
|
|
—
|
|
|
—
|
|
|
21,157
|
|
|||||
|
Production and ad valorem taxes
|
—
|
|
|
11,927
|
|
|
972
|
|
|
—
|
|
|
12,899
|
|
|||||
|
Gathering and transportation
|
—
|
|
|
918
|
|
|
—
|
|
|
—
|
|
|
918
|
|
|||||
|
Depreciation, depletion and amortization
|
—
|
|
|
61,398
|
|
|
5,199
|
|
|
—
|
|
|
66,597
|
|
|||||
|
General and administrative expenses
|
3,909
|
|
|
7,127
|
|
|
—
|
|
|
—
|
|
|
11,036
|
|
|||||
|
Asset retirement obligation accretion expense
|
—
|
|
|
201
|
|
|
—
|
|
|
—
|
|
|
201
|
|
|||||
|
Intercompany charges
|
—
|
|
|
—
|
|
|
87
|
|
|
(87
|
)
|
|
—
|
|
|||||
|
Total costs and expenses
|
3,909
|
|
|
102,728
|
|
|
6,258
|
|
|
(87
|
)
|
|
112,808
|
|
|||||
|
Income (loss) from operations
|
(3,909
|
)
|
|
90,287
|
|
|
8,729
|
|
|
87
|
|
|
95,194
|
|
|||||
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Interest income - intercompany
|
5,741
|
|
|
—
|
|
|
—
|
|
|
(5,741
|
)
|
|
—
|
|
|||||
|
Interest expense
|
(591
|
)
|
|
(7,467
|
)
|
|
(5,741
|
)
|
|
5,741
|
|
|
(8,058
|
)
|
|||||
|
Other income
|
—
|
|
|
87
|
|
|
—
|
|
|
(87
|
)
|
|
—
|
|
|||||
|
Other income - intercompany
|
—
|
|
|
1,077
|
|
|
—
|
|
|
—
|
|
|
1,077
|
|
|||||
|
Loss on derivative instruments, net
|
—
|
|
|
(1,872
|
)
|
|
—
|
|
|
—
|
|
|
(1,872
|
)
|
|||||
|
Total other income (expense), net
|
5,150
|
|
|
(8,175
|
)
|
|
(5,741
|
)
|
|
(87
|
)
|
|
(8,853
|
)
|
|||||
|
Income (loss) before income taxes
|
1,241
|
|
|
82,112
|
|
|
2,988
|
|
|
—
|
|
|
86,341
|
|
|||||
|
Provision for income taxes
|
31,754
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31,754
|
|
|||||
|
Net income (loss)
|
$
|
(30,513
|
)
|
|
$
|
82,112
|
|
|
$
|
2,988
|
|
|
$
|
—
|
|
|
$
|
54,587
|
|
|
Condensed Consolidated Statement of Cash Flows
|
|||||||||||||||||||
|
Year Ended December 31, 2015
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Net cash provided by (used in) operating activities
|
$
|
(37,597
|
)
|
|
$
|
390,266
|
|
|
$
|
63,832
|
|
|
$
|
—
|
|
|
$
|
416,501
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Additions to oil and natural gas properties
|
—
|
|
|
(419,512
|
)
|
|
—
|
|
|
—
|
|
|
(419,512
|
)
|
|||||
|
Acquisition of leasehold interests
|
—
|
|
|
(437,455
|
)
|
|
—
|
|
|
—
|
|
|
(437,455
|
)
|
|||||
|
Acquisition of royalty interests
|
—
|
|
|
—
|
|
|
(43,907
|
)
|
|
—
|
|
|
(43,907
|
)
|
|||||
|
Purchase of other property and equipment
|
—
|
|
|
(1,213
|
)
|
|
—
|
|
|
—
|
|
|
(1,213
|
)
|
|||||
|
Proceeds from sale of assets
|
—
|
|
|
9,739
|
|
|
—
|
|
|
—
|
|
|
9,739
|
|
|||||
|
Equity investments
|
—
|
|
|
(2,702
|
)
|
|
—
|
|
|
—
|
|
|
(2,702
|
)
|
|||||
|
Intercompany transfers
|
(145,023
|
)
|
|
145,023
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Other investing activities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Net cash used in investing activities
|
(145,023
|
)
|
|
(706,120
|
)
|
|
(43,907
|
)
|
|
—
|
|
|
(895,050
|
)
|
|||||
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Proceeds from borrowing on credit facility
|
—
|
|
|
390,501
|
|
|
34,500
|
|
|
—
|
|
|
425,001
|
|
|||||
|
Repayment on credit facility
|
—
|
|
|
(603,001
|
)
|
|
—
|
|
|
—
|
|
|
(603,001
|
)
|
|||||
|
Debit issuance costs
|
—
|
|
|
(85
|
)
|
|
(441
|
)
|
|
—
|
|
|
(526
|
)
|
|||||
|
Public offering costs
|
(586
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(586
|
)
|
|||||
|
Proceeds from public offerings
|
650,688
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
650,688
|
|
|||||
|
Distribution to parent
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Distribution from subsidiary
|
60,587
|
|
|
—
|
|
|
—
|
|
|
(60,587
|
)
|
|
—
|
|
|||||
|
Exercise of stock options
|
4,873
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,873
|
|
|||||
|
Distribution to non-controlling interest
|
—
|
|
|
—
|
|
|
(68,555
|
)
|
|
60,587
|
|
|
(7,968
|
)
|
|||||
|
Intercompany transfers
|
(532,800
|
)
|
|
532,800
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Net cash provided by financing activities
|
182,762
|
|
|
320,215
|
|
|
(34,496
|
)
|
|
—
|
|
|
468,481
|
|
|||||
|
Net increase (decrease) in cash and cash equivalents
|
142
|
|
|
4,361
|
|
|
(14,571
|
)
|
|
—
|
|
|
(10,068
|
)
|
|||||
|
Cash and cash equivalents at beginning of period
|
6
|
|
|
15,067
|
|
|
15,110
|
|
|
—
|
|
|
30,183
|
|
|||||
|
Cash and cash equivalents at end of period
|
$
|
148
|
|
|
$
|
19,428
|
|
|
$
|
539
|
|
|
$
|
—
|
|
|
$
|
20,115
|
|
|
Condensed Consolidated Statement of Cash Flows
|
|||||||||||||||||||
|
Year Ended December 31, 2014
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Net cash provided by (used in) operating activities
|
$
|
(8,862
|
)
|
|
$
|
313,438
|
|
|
$
|
51,813
|
|
|
$
|
—
|
|
|
$
|
356,389
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Additions to oil and natural gas properties
|
—
|
|
|
(493,063
|
)
|
|
(5,276
|
)
|
|
—
|
|
|
(498,339
|
)
|
|||||
|
Acquisition of leasehold interests
|
—
|
|
|
(845,826
|
)
|
|
—
|
|
|
—
|
|
|
(845,826
|
)
|
|||||
|
Acquisition of royalty interests
|
—
|
|
|
—
|
|
|
(57,689
|
)
|
|
—
|
|
|
(57,689
|
)
|
|||||
|
Purchase of other property and equipment
|
—
|
|
|
(44,213
|
)
|
|
—
|
|
|
—
|
|
|
(44,213
|
)
|
|||||
|
Equity investments
|
—
|
|
|
(627
|
)
|
|
(33,850
|
)
|
|
—
|
|
|
(34,477
|
)
|
|||||
|
Intercompany transfers
|
(642,978
|
)
|
|
642,978
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Other investing activities
|
—
|
|
|
(1,453
|
)
|
|
—
|
|
|
—
|
|
|
(1,453
|
)
|
|||||
|
Net cash used in investing activities
|
(642,978
|
)
|
|
(742,204
|
)
|
|
(96,815
|
)
|
|
—
|
|
|
(1,481,997
|
)
|
|||||
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Proceeds from borrowing on credit facility
|
—
|
|
|
431,400
|
|
|
78,000
|
|
|
—
|
|
|
509,400
|
|
|||||
|
Repayment on credit facility
|
—
|
|
|
(217,900
|
)
|
|
(78,000
|
)
|
|
—
|
|
|
(295,900
|
)
|
|||||
|
Proceeds from public offerings
|
693,886
|
|
|
—
|
|
|
234,546
|
|
|
—
|
|
|
928,432
|
|
|||||
|
Distribution to parent
|
—
|
|
|
—
|
|
|
(148,760
|
)
|
|
148,760
|
|
|
—
|
|
|||||
|
Distribution from subsidiary
|
166,372
|
|
|
—
|
|
|
—
|
|
|
(166,372
|
)
|
|
—
|
|
|||||
|
Distribution to non-controlling interest
|
—
|
|
|
—
|
|
|
(19,926
|
)
|
|
17,612
|
|
|
(2,314
|
)
|
|||||
|
Intercompany transfers
|
(217,900
|
)
|
|
217,900
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Other financing activities
|
8,962
|
|
|
(1,834
|
)
|
|
(6,510
|
)
|
|
—
|
|
|
618
|
|
|||||
|
Net cash provided by financing activities
|
651,320
|
|
|
429,566
|
|
|
59,350
|
|
|
—
|
|
|
1,140,236
|
|
|||||
|
Net increase (decrease) in cash and cash equivalents
|
(520
|
)
|
|
800
|
|
|
14,348
|
|
|
—
|
|
|
14,628
|
|
|||||
|
Cash and cash equivalents at beginning of period
|
526
|
|
|
14,267
|
|
|
762
|
|
|
—
|
|
|
15,555
|
|
|||||
|
Cash and cash equivalents at end of period
|
$
|
6
|
|
|
$
|
15,067
|
|
|
$
|
15,110
|
|
|
$
|
—
|
|
|
$
|
30,183
|
|
|
Condensed Consolidated Statement of Cash Flows
|
|||||||||||||||||||
|
Year Ended December 31, 2013
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||
|
|
|
|
|
|
Non–
|
|
|
|
|
||||||||||
|
|
|
|
Guarantor
|
|
Guarantor
|
|
|
|
|
||||||||||
|
|
Parent
|
|
Subsidiaries
|
|
Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
|
Net cash provided by operating activities
|
$
|
12,302
|
|
|
$
|
138,630
|
|
|
$
|
4,845
|
|
|
$
|
—
|
|
|
$
|
155,777
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Additions to oil and natural gas properties
|
—
|
|
|
(292,586
|
)
|
|
—
|
|
|
—
|
|
|
(292,586
|
)
|
|||||
|
Acquisition of leasehold interests
|
—
|
|
|
(195,893
|
)
|
|
—
|
|
|
—
|
|
|
(195,893
|
)
|
|||||
|
Acquisition of royalty interests
|
—
|
|
|
—
|
|
|
(444,083
|
)
|
|
—
|
|
|
(444,083
|
)
|
|||||
|
Intercompany transfers
|
(289,344
|
)
|
|
289,344
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Other investing activities
|
—
|
|
|
(7,578
|
)
|
|
—
|
|
|
—
|
|
|
(7,578
|
)
|
|||||
|
Net cash used in investing activities
|
(289,344
|
)
|
|
(206,713
|
)
|
|
(444,083
|
)
|
|
—
|
|
|
(940,140
|
)
|
|||||
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Proceeds from borrowing on credit facility
|
—
|
|
|
59,000
|
|
|
—
|
|
|
—
|
|
|
59,000
|
|
|||||
|
Repayment on credit facility
|
—
|
|
|
(49,000
|
)
|
|
—
|
|
|
—
|
|
|
(49,000
|
)
|
|||||
|
Proceeds from senior notes
|
10,000
|
|
|
—
|
|
|
440,000
|
|
|
—
|
|
|
450,000
|
|
|||||
|
Proceeds from public offerings
|
322,680
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
322,680
|
|
|||||
|
Intercompany transfers
|
(49,000
|
)
|
|
49,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
Other financing activities
|
(6,126
|
)
|
|
(2,994
|
)
|
|
—
|
|
|
—
|
|
|
(9,120
|
)
|
|||||
|
Net cash provided by financing activities
|
277,554
|
|
|
56,006
|
|
|
440,000
|
|
|
—
|
|
|
773,560
|
|
|||||
|
Net increase in cash and cash equivalents
|
512
|
|
|
(12,077
|
)
|
|
762
|
|
|
—
|
|
|
(10,803
|
)
|
|||||
|
Cash and cash equivalents at beginning of period
|
14
|
|
|
26,344
|
|
|
—
|
|
|
—
|
|
|
26,358
|
|
|||||
|
Cash and cash equivalents at end of period
|
$
|
526
|
|
|
$
|
14,267
|
|
|
$
|
762
|
|
|
$
|
—
|
|
|
$
|
15,555
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(In thousands)
|
||||||
|
Oil and Natural Gas Properties:
|
|
|
|
||||
|
Proved properties
|
$
|
2,848,557
|
|
|
$
|
2,345,077
|
|
|
Unproved properties
|
1,106,816
|
|
|
773,520
|
|
||
|
Total Oil and Natural Gas Properties
|
3,955,373
|
|
|
3,118,597
|
|
||
|
Accumulated depreciation, depletion, amortization
|
(512,144
|
)
|
|
(296,317
|
)
|
||
|
Accumulated impairment
|
(897,962
|
)
|
|
(83,164
|
)
|
||
|
Net oil and natural gas properties capitalized
|
$
|
2,545,267
|
|
|
$
|
2,739,116
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Acquisition costs
|
|
|
|
|
|
||||||
|
Proved properties
|
$
|
64,340
|
|
|
$
|
302,234
|
|
|
$
|
339,130
|
|
|
Unproved properties
|
448,638
|
|
|
601,188
|
|
|
279,402
|
|
|||
|
Development costs
|
42,749
|
|
|
86,097
|
|
|
88,460
|
|
|||
|
Exploration costs
|
319,102
|
|
|
475,756
|
|
|
242,929
|
|
|||
|
Capitalized asset retirement costs
|
3,458
|
|
|
4,962
|
|
|
697
|
|
|||
|
Total
|
$
|
878,287
|
|
|
$
|
1,470,237
|
|
|
$
|
950,618
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Oil, natural gas and natural gas liquid sales
|
$
|
446,733
|
|
|
$
|
495,718
|
|
|
$
|
208,002
|
|
|
Lease operating expenses
|
(82,625
|
)
|
|
(55,384
|
)
|
|
(21,157
|
)
|
|||
|
Production and ad valorem taxes
|
(32,990
|
)
|
|
(32,638
|
)
|
|
(12,899
|
)
|
|||
|
Gathering and transportation
|
(6,091
|
)
|
|
(3,288
|
)
|
|
(918
|
)
|
|||
|
Depreciation, depletion, and amortization
|
(216,056
|
)
|
|
(168,674
|
)
|
|
(65,821
|
)
|
|||
|
Impairment
|
(814,798
|
)
|
|
—
|
|
|
—
|
|
|||
|
Asset retirement obligation accretion expense
|
(833
|
)
|
|
(467
|
)
|
|
(201
|
)
|
|||
|
Income tax expense
|
201,310
|
|
|
(108,985
|
)
|
|
(31,754
|
)
|
|||
|
Results of operations
|
$
|
(505,350
|
)
|
|
$
|
126,282
|
|
|
$
|
75,252
|
|
|
|
Oil
(Bbls) |
|
Natural Gas
Liquids (Bbls) |
|
Natural Gas
(Mcf) |
|||
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|||
|
As of January 1, 2013
|
26,196,859
|
|
|
8,251,429
|
|
|
34,570,148
|
|
|
Extensions and discoveries
|
17,041,744
|
|
|
4,597,856
|
|
|
24,184,540
|
|
|
Revisions of previous estimates
|
(5,943,164
|
)
|
|
(3,455,306
|
)
|
|
(5,786,180
|
)
|
|
Purchase of reserves in place
|
7,328,162
|
|
|
1,672,824
|
|
|
10,441,485
|
|
|
Production
|
(2,022,749
|
)
|
|
(361,079
|
)
|
|
(1,730,497
|
)
|
|
As of December 31, 2013
|
42,600,852
|
|
|
10,705,724
|
|
|
61,679,496
|
|
|
Extensions and discoveries
|
37,068,820
|
|
|
7,828,094
|
|
|
52,099,252
|
|
|
Revisions of previous estimates
|
(6,784,560
|
)
|
|
649,476
|
|
|
(17,726,552
|
)
|
|
Purchase of reserves in place
|
8,186,053
|
|
|
360,536
|
|
|
19,898,649
|
|
|
Production
|
(5,381,576
|
)
|
|
(1,001,898
|
)
|
|
(4,345,585
|
)
|
|
As of December 31, 2014
|
75,689,589
|
|
|
18,541,932
|
|
|
111,605,260
|
|
|
Extensions and discoveries
|
48,725,132
|
|
|
12,055,631
|
|
|
53,452,948
|
|
|
Revisions of previous estimates
|
(12,130,474
|
)
|
|
(4,080,886
|
)
|
|
(14,726,160
|
)
|
|
Purchase of reserves in place
|
2,775,599
|
|
|
1,165,090
|
|
|
7,101,933
|
|
|
Production
|
(9,081,135
|
)
|
|
(1,677,623
|
)
|
|
(7,931,237
|
)
|
|
As of December 31, 2015
|
105,978,711
|
|
|
26,004,144
|
|
|
149,502,744
|
|
|
|
|
|
|
|
|
|||
|
Proved Developed Reserves:
|
|
|
|
|
|
|||
|
January 1, 2013
|
7,189,367
|
|
|
2,999,440
|
|
|
12,864,941
|
|
|
December 31, 2013
|
19,789,965
|
|
|
4,973,493
|
|
|
31,428,756
|
|
|
December 31, 2014
|
43,885,835
|
|
|
11,221,428
|
|
|
68,264,113
|
|
|
December 31, 2015
|
60,569,398
|
|
|
15,418,353
|
|
|
96,871,109
|
|
|
|
|
|
|
|
|
|||
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|||
|
January 1, 2013
|
19,007,492
|
|
|
5,251,989
|
|
|
21,705,207
|
|
|
December 31, 2013
|
22,810,887
|
|
|
5,732,231
|
|
|
30,250,740
|
|
|
December 31, 2014
|
31,803,754
|
|
|
7,320,504
|
|
|
43,341,147
|
|
|
December 31, 2015
|
45,409,313
|
|
|
10,585,791
|
|
|
52,631,635
|
|
|
|
(MBOE)
|
|
|
Beginning proved undeveloped reserves at December 31, 2014
|
46,348
|
|
|
Undeveloped reserves transferred to developed
|
(13,680
|
)
|
|
Revisions
|
(12,656
|
)
|
|
Extensions and discoveries
|
44,755
|
|
|
Ending proved undeveloped reserves at December 31, 2015
|
64,767
|
|
|
|
December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Future cash inflows
|
$
|
5,377,783
|
|
|
$
|
7,695,368
|
|
|
$
|
4,604,241
|
|
|
Future development costs
|
(548,239
|
)
|
|
(602,438
|
)
|
|
(517,075
|
)
|
|||
|
Future production costs
|
(1,279,101
|
)
|
|
(1,278,487
|
)
|
|
(806,895
|
)
|
|||
|
Future production taxes
|
(363,129
|
)
|
|
(534,851
|
)
|
|
(318,396
|
)
|
|||
|
Future income tax expenses
|
(28,233
|
)
|
|
(672,380
|
)
|
|
(674,260
|
)
|
|||
|
Future net cash flows
|
3,159,081
|
|
|
4,607,212
|
|
|
2,287,615
|
|
|||
|
10% discount to reflect timing of cash flows
|
(1,740,948
|
)
|
|
(2,561,988
|
)
|
|
(1,311,976
|
)
|
|||
|
Standardized measure of discounted future net cash flows
|
$
|
1,418,133
|
|
|
$
|
2,045,224
|
|
|
$
|
975,639
|
|
|
|
December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
Unweighted Arithmetic Average
|
||||||||||
|
|
First-Day-of-the-Month Prices
|
||||||||||
|
Oil (per Bbl)
|
$
|
45.07
|
|
|
$
|
87.15
|
|
|
$
|
92.59
|
|
|
Natural gas (per Mcf)
|
$
|
1.83
|
|
|
$
|
4.85
|
|
|
$
|
4.13
|
|
|
Natural gas liquids (per Bbl)
|
$
|
12.56
|
|
|
$
|
30.09
|
|
|
$
|
37.82
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(In thousands)
|
||||||||||
|
Standardized measure of discounted future net cash flows at the beginning of the period
|
$
|
2,045,224
|
|
|
$
|
975,639
|
|
|
$
|
367,220
|
|
|
Sales of oil and natural gas, net of production costs
|
(331,119
|
)
|
|
(404,409
|
)
|
|
(173,946
|
)
|
|||
|
Purchase of minerals in place
|
57,359
|
|
|
291,807
|
|
|
305,109
|
|
|||
|
Extensions and discoveries, net of future development costs
|
629,149
|
|
|
1,135,293
|
|
|
552,450
|
|
|||
|
Previously estimated development costs incurred during the period
|
129,901
|
|
|
111,527
|
|
|
76,631
|
|
|||
|
Net changes in prices and production costs
|
(1,383,698
|
)
|
|
(105,210
|
)
|
|
51,828
|
|
|||
|
Changes in estimated future development costs
|
38,638
|
|
|
(4,877
|
)
|
|
(5,822
|
)
|
|||
|
Revisions of previous quantity estimates
|
(377,160
|
)
|
|
(173,004
|
)
|
|
(126,993
|
)
|
|||
|
Accretion of discount
|
236,716
|
|
|
151,481
|
|
|
57,988
|
|
|||
|
Net change in income taxes
|
268,963
|
|
|
(12,326
|
)
|
|
(168,570
|
)
|
|||
|
Net changes in timing of production and other
|
104,160
|
|
|
79,303
|
|
|
39,744
|
|
|||
|
Standardized measure of discounted future net cash flows at the end of the period
|
$
|
1,418,133
|
|
|
$
|
2,045,224
|
|
|
$
|
975,639
|
|
|
|
2015
|
||||||||||||||
|
|
First
Quarter |
|
Second
Quarter |
|
Third
Quarter |
|
Fourth
Quarter |
||||||||
|
Revenues
|
$
|
101,401
|
|
|
$
|
119,063
|
|
|
$
|
111,946
|
|
|
$
|
114,323
|
|
|
Income (loss) from operations
|
1,437
|
|
|
(299,120
|
)
|
|
(254,773
|
)
|
|
(187,813
|
)
|
||||
|
Income tax expense (benefit)
|
3,370
|
|
|
(116,732
|
)
|
|
(81,461
|
)
|
|
(6,487
|
)
|
||||
|
Net income (loss)
|
6,439
|
|
|
(211,352
|
)
|
|
(156,042
|
)
|
|
(186,835
|
)
|
||||
|
Less: Net income attributable to noncontrolling interest
|
590
|
|
|
935
|
|
|
739
|
|
|
574
|
|
||||
|
Net income (loss) attributable to Diamondback Energy, Inc.
|
$
|
5,849
|
|
|
$
|
(212,287
|
)
|
|
$
|
(156,781
|
)
|
|
$
|
(187,409
|
)
|
|
Earnings per common share
|
|
|
|
|
|
|
|
||||||||
|
Basic
|
$
|
0.10
|
|
|
$
|
(3.45
|
)
|
|
$
|
(2.40
|
)
|
|
$
|
(2.80
|
)
|
|
Diluted
|
$
|
0.10
|
|
|
$
|
(3.45
|
)
|
|
$
|
(2.40
|
)
|
|
$
|
(2.80
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
2014
|
||||||||||||||
|
|
First
Quarter |
|
Second
Quarter |
|
Third
Quarter |
|
Fourth
Quarter |
||||||||
|
Revenues
|
$
|
98,004
|
|
|
$
|
127,004
|
|
|
$
|
139,127
|
|
|
$
|
131,583
|
|
|
Income from operations
|
48,063
|
|
|
63,192
|
|
|
63,516
|
|
|
37,899
|
|
||||
|
Income tax expense (benefit)
|
13,601
|
|
|
15,163
|
|
|
23,978
|
|
|
56,243
|
|
||||
|
Net income
|
23,589
|
|
|
27,824
|
|
|
44,641
|
|
|
99,917
|
|
||||
|
Less: Net income attributable to noncontrolling interest
|
—
|
|
|
71
|
|
|
902
|
|
|
1,243
|
|
||||
|
Net income attributable to Diamondback Energy, Inc.
|
$
|
23,589
|
|
|
$
|
27,753
|
|
|
$
|
43,739
|
|
|
$
|
98,674
|
|
|
Earnings per common share
|
|
|
|
|
|
|
|
||||||||
|
Basic
|
$
|
0.49
|
|
|
$
|
0.55
|
|
|
$
|
0.79
|
|
|
$
|
1.74
|
|
|
Diluted
|
$
|
0.48
|
|
|
$
|
0.54
|
|
|
$
|
0.79
|
|
|
$
|
1.73
|
|
|
Exhibit Number
|
|
Description
|
|
2.1#
|
|
Purchase and Sale Agreement dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, and FC Permian Properties, Inc., as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
|
|
2.2#
|
|
Purchase and Sale Agreement, dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, FC Permian Properties, Inc., Blake Braun, Richard D. Campbell, and Thomas J. Woodside, as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
|
|
2.3#
|
|
Purchase and Sale Agreement by and among Rio Oil and Gas, LLC, Rio Oil and Gas (Permian) LLC, Rio Oil and Gas (OPCO), LLC, Bluestem Energy, LP, Bluestem Energy Partners, LP, Bluestem Energy Holdings, LLC, Bluestem Energy Assets, LLC, Bluestem Acquisitions, LLC, BC Operating, Inc., Crown Oil Partners V, LP and Crump Energy Partners II, LLC, as sellers, and Diamondback E&P LLC, as buyer, dated July 18, 2014 (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on July 21, 2014).
|
|
3.1
|
|
Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
3.2
|
|
Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
4.1
|
|
Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
4.2
|
|
Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC (incorporated by reference to Exhibit 4.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
4.3
|
|
Indenture, dated as of September 18, 2013, among Diamondback Energy, Inc., the subsidiary guarantors party thereto and Wells Fargo, N.A., as trustee (including the form of Diamondback Energy, Inc.’s 7.625% Senior Note due October 2021 (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 18, 2013).
|
|
4.4
|
|
First Supplemental Indenture, dated as of November 5, 2013, by and among Diamondback Energy, Inc., the subsidiary guarantors party thereto and Wells Fargo, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 19, 2014).
|
|
4.5
|
|
Second Supplemental Indenture, dated as of October 8, 2014, by and among Diamondback Energy, Inc., White Fang Energy LLC, as subsidiary guarantor, other subsidiary guarantors party thereto and Wells Fargo, National Association, as trustee (incorporated by reference to Exhibit 4.6 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 19, 2015).
|
|
10.1+
|
|
Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
10.2+
|
|
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.3+
|
|
Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.4+
|
|
Form of Director and Officer Indemnification Agreement (incorporated by reference to
Exhibit 10.15 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012). |
|
10.5
|
|
Advisory Services Agreement, dated as of October 11, 2012, by and between Diamondback Energy, Inc. and Wexford Capital LP (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
Exhibit Number
|
|
Description
|
|
10.6
|
|
Merger Agreement, dated as of October 11, 2012, by and between the Company and Diamondback Energy LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
|
|
10.7+
|
|
Amended and Restated Employment Agreement, dated April 24, 2014, effective as of April 18, 2014, by and between Travis D. Stice and Diamondback E&P LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-035700, filed by the Company with the SEC on May 9, 2014 ).
|
|
10.8+
|
|
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Teresa Dick and Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
|
|
10.9+
|
|
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Michael Hollis and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
|
|
10.10+
|
|
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Jeff White and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
|
|
10.11+
|
|
Amended and Restated Employment Agreement, dated as of February 27, 2014, effective as of January 1, 2014, by and between Russell Pantermuehl and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-035700, filed by the Company with the SEC on May 9, 2014 ).
|
|
10.12+
|
|
2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on April 2, 2014).
|
|
10.13+
|
|
Form of Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
|
|
10.14+
|
|
Form of Performance-Based Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 5, 2014).
|
|
10.15
|
|
Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on June 11, 2012).
|
|
10.16
|
|
Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.17
|
|
Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.18
|
|
Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.19
|
|
Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.20
|
|
Lease Amendment No. 5 to Lease Agreement, dated as of July 25, 2012, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.36 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).
|
|
10.21
|
|
Contribution Agreement, dated May 7, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.22
|
|
Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
Exhibit Number
|
|
Description
|
|
10.23
|
|
Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.24
|
|
Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.25
|
|
Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on May 8, 2012).
|
|
10.26
|
|
Crude Oil Purchase Agreement, dated May 24, 2012, by and between Windsor Permian LLC and Shell Trading (US) Company (incorporated by reference to Exhibit 10.26 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
|
|
10.27
|
|
Master Drilling Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
|
|
10.28
|
|
Master Field Services Agreement, effective as of January 1, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 1, 2013).
|
|
10.29
|
|
First Amendment to Master Field Services Agreement, dated as of February 21, 2013, by and between Diamondback E&P LLC and Bison Drilling and Field Services LLC (incorporated by reference to Exhibit 10.35 to the Form 10-K, file No. 001-35700, filed by the Company with the SEC on March 1, 2013).
|
|
10.30+
|
|
Form of Amendment to Restricted Stock Unit Certificate (incorporated by reference to Exhibit 10.38 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).
|
|
10.31
|
|
Lease Amendment No. 6 effective May 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.39 to the Form 10-K/A, file No. 001-35700, filed by the Company with the SEC on April 10, 2013).
|
|
10.32
|
|
Lease Amendment No. 7 effective September 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 8, 2013).
|
|
10.33
|
|
Lease Amendment No. 8 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 8, 2013).
|
|
10.34
|
|
Lease Amendment No. 9 effective August 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
|
|
10.35
|
|
Lease Amendment No. 10 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
|
|
10.36
|
|
Second Amended and Restated Credit Agreement, dated as of November 1, 2103, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2013).
|
|
10.37
|
|
First Amendment, dated June 9, 2014, to the Second Amended and Restated Credit Agreement, originally dated November 1, 2013, by and among the Company, as parent guarantor, Diamondback O&G LLC, as borrower, each of the guarantors party thereto, each of the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 7, 2014).
|
|
10.38
|
|
Second Amendment to the Second Amended and Restated Credit Agreement, dated as of November 13, 2014, among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, the guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 18, 2014).
|
|
Exhibit Number
|
|
Description
|
|
10.39
|
|
Senior Secured Revolving Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, Wells Fargo Bank, National Association, as the administrative agent, sole book runner and lead arranger, and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-36505, filed by Viper Energy Partners LP on July 14, 2014).
|
|
10.40
|
|
Contribution Agreement by and among Diamondback Energy, Inc., Viper Energy Partners LLC, Viper Energy Partners GP LLC and Viper Energy Partners LP, dated as of June 17, 2014 (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on May 9, 2014).
|
|
10.41
|
|
First Amendment, dated as of August 15, 2014, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 6, 2015).
|
|
10.42
|
|
Second Amendment, dated as of May 22, 2015, to Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower, the guarantors party thereto, Wells Fargo, National Association, as administrative agent, and certain lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 6, 2015).
|
|
10.43
|
|
Lease Amendment No. 11 effective July 31, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
|
|
10.44
|
|
Lease Amendment No. 12 effective October 23, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
|
|
10.45
|
|
Lease Amendment No. 13 effective October 30, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
|
|
10.46
|
|
Lease Amendment No. 14 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
|
|
10.47
|
|
Lease Amendment No. 15 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
|
|
10.48
|
|
Lease Amendment No. 16 effective April 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
|
|
10.49
|
|
Lease Amendment No. 17 effective June 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 5, 2015).
|
|
21.1*
|
|
Subsidiaries of the Registrant.
|
|
23.1*
|
|
Consent of Grant Thornton LLP.
|
|
23.2*
|
|
Consent of Ryder Scott Company, L.P. with respect to the Diamondback Energy, Inc. reserve report included as Exhibit 99.1.
|
|
23.3*
|
|
Consent of Ryder Scott Company, L.P. with respect to the Viper Energy Partners LP reserve report included as Exhibit 99.2.
|
|
31.1*
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
31.2*
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
|
|
32.1**
|
|
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
Exhibit Number
|
|
Description
|
|
32.2**
|
|
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
|
|
99.1*
|
|
Report of Ryder Scott Company, L.P., dated January 21, 2016, with respect to an estimate of the proved reserves, future production and income attributable to certain leasehold interests of Diamondback Energy, Inc. as of December 31, 2015.
|
|
99.2*
|
|
Report of Ryder Scott Company, L.P., dated January 21, 2016, with respect to an estimate of the proved reserves, future production and income attributable to certain royalty interests of Viper Energy Partners LP, a subsidiary of Diamondback Energy, Inc., as of December 31, 2015.
|
|
101.INS*
|
|
XBRL Instance Document.
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase.
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
*
|
Filed herewith.
|
|
**
|
The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
|
|
+
|
Management contract, compensatory plan or arrangement.
|
|
#
|
The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.
|
No information found
* THE VALUE IS THE MARKET VALUE AS OF THE LAST DAY OF THE QUARTER FOR WHICH THE 13F WAS FILED.
| FUND | NUMBER OF SHARES | VALUE ($) | PUT OR CALL |
|---|
| DIRECTORS | AGE | BIO | OTHER DIRECTOR MEMBERSHIPS |
|---|
No information found
No Customers Found
No Suppliers Found
Price
Yield
| Owner | Position | Direct Shares | Indirect Shares |
|---|