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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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32-0498321
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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14201 Caliber Drive, Suite 300
Oklahoma City, Oklahoma
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(405) 608-6007
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73134
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(Address of principal executive offices)
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(Registrant’s telephone number, including area code)
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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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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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Emerging growth company
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Page
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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Item 5.
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Item 6.
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Item 7.
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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Item 15.
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Item 16.
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The following is a glossary of certain oil and natural gas and natural sand proppant industry terms used in this report:
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Blowout
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An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of salt water, oil, natural gas or a mixture of these. Blowouts can occur in all types of exploration and production operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant open-hole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) down-hole and intervention efforts will be averted.
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Bottomhole assembly
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The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.
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Cementing
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To prepare and pump cement into place in a wellbore.
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Coiled tubing
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A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft. to 23,000 ft. (610 m to 6,096 m) or greater length.
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Completion
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A generic term used to describe the assembly of down-hole tubulars and equipment required to enable safe and efficient production from an oil or gas well. The point at which the completion process begins may depend on the type and design of the well.
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Directional drilling
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The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken down-hole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a down-hole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes.
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Down-hole
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Pertaining to or in the wellbore (as opposed to being on the surface).
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Down-hole motor
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A drilling motor located in the drill string above the drilling bit powered by the flow of drilling mud. Down-hole motors are used to increase the speed and efficiency of the drill bit or can be used to steer the bit in directional drilling operations. Drilling motors have become very popular because of horizontal and directional drilling applications and the day rates for drilling rigs.
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Drilling rig
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The machine used to drill a wellbore.
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Drillpipe or Drill pipe
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Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.
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Drillstring or Drill string
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The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.
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Horizontal drilling
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A subset of the more general term “directional drilling,” used where the departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting it as deviation from vertical, which would then be 85 degrees. Because a horizontal well typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical well.
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Hydraulic fracturing
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A stimulation treatment routinely performed on oil and gas wells in low permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation. Proppant, such as grains of sand of a particular size, is mixed with the treatment fluid to keep the fracture open when the treatment is complete. Hydraulic fracturing creates high-conductivity communication with a large area of formation and bypasses any damage that may exist in the near-wellbore area.
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Hydrocarbon
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A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.
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Mesh size
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The size of the proppant that is determined by sieving the proppant through screens with uniform openings corresponding to the desired size of the proppant. Each type of proppant comes in various sizes, categorized as mesh sizes, and the various mesh sizes are used in different applications in the oil and natural gas industry. The mesh number system is a measure of the number of equally sized openings per square inch of screen through which the proppant is sieved.
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The following is a glossary of certain electrical infrastructure industry terms used in this report:
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Distribution
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The distribution of electricity from the transmission system to individual customers.
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Substation
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A part of an electrical transmission and distribution system that transforms voltage from high to low, or the reverse.
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Transmission
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The movement of electrical energy from a generating site, such as a power plant, to an electric substation.
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business strategy;
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pending or future acquisitions and future capital expenditures;
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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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future operating results; and
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plans, objectives, expectations and intentions.
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The Utica Shale in Eastern Ohio;
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Southern Ohio;
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The Permian Basin in West Texas;
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The Appalachian Basin in the Northeast;
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The SCOOP and STACK in Oklahoma;
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The Arkoma Basin in Arkansas and Oklahoma;
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The Anadarko Basin in Oklahoma;
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The Marcellus Shale in West Virginia and Pennsylvania;
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Southeastern New Mexico;
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The Barnett Shale in Texas;
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The Granite Wash and Mississippi Shale in Oklahoma and Texas;
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The Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma;
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The Eagle Ford Shale in Texas;
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Puerto Rico; and
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The oil sands in Alberta, Canada.
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Hydraulic Fracturing.
We provide high-pressure hydraulic fracturing services. Fracturing services are performed to enhance the production of oil and natural gas from formations having low permeability such that the flow of hydrocarbons is restricted. We have significant expertise in multistage fracturing of horizontal oil and natural gas producing wells in shale and other unconventional geological formations.
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Nitrogen Services.
Nitrogen services involve the use of nitrogen, an inert gas, in various pressure pumping operations. When provided as a stand-alone service, nitrogen is used in displacing fluids in various oilfield applications. As of December 31, 2017, we had a total of four nitrogen pumping units capable of pumping at a rate of up to 3,000 standard cubic feet per minute with pressures up to 10,000 psi. Pumping at these rates and pressures is typically required for the unconventional oil and natural gas resource plays we serve.
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Fluid Pumping Services.
Fluid pumping services consist of maintaining well pressure, pumping down wireline tools, assisting coiled tubing units and the removal of fluids and solids from the wellbore for clean-out operations. As of December 31, 2017, we had five fluid pumping units. All five are coiled tubing double pump units capable of output of up to eight barrels per minute, and are rated for pressures up to 15,000 psi.
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Production Testing.
Production testing focuses on testing production potential. Key measurements are recorded to determine activity both above and below ground. Production testing and the knowledge it provides help our customers determine where they can more efficiently deploy capital. As of December 31, 2017, we had five production testing packages.
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Solids Control.
Solids control services provide prepared drilling fluids for drilling rigs with equipment such as sand separators and plug catchers. These services reduce costs throughout the entire drilling process. As of December 31, 2017, we had ten solids control packages.
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Hydrostatic Testing.
Hydrostatic testing is a procedure in which pressure vessels, such as pipelines, are tested for damage or leaks. This method of testing helps maintain safety standards and increases the durability of the pipeline. We employ hydrostatic testing at industry standards and to a customer’s desired specifications and configuration. As of December 31, 2017, we had two hydrostatic testing packages.
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Torque Services.
Torque refers to the force applied to a rotary device to make it rotate. We offer a comprehensive range of torque services, offering a customer the dual benefit of reducing costs on the rig as well as reducing hazards for both personnel and equipment. We had five torque service packages as of December 31, 2017.
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Increased U.S. Petroleum field Production.
According to the U.S. Energy Information Administration, or EIA, U.S. average petroleum field production was approximately 10.0 million barrels per day during November 2017, only 1.5% below the record high average daily petroleum field production set in 2015. U.S. average petroleum field production has grown at a compound annual growth rate of 9.8% over the period from 2009 through 2015 due to production gains from unconventional reservoirs. We expect that this continued growth will result in increased demand for our services as commodity prices continue to stabilize and increase.
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Increased use of horizontal drilling to develop unconventional resource plays.
According to Baker Hughes, the horizontal rig count on December 29, 2017 was 796, or approximately 86% of the total U.S. onshore rig count. The overall onshore rig count increased significantly from May 2016 to September 2017 from 404 rigs operating to 940 rigs operating. The horizontal rig count as a percentage of the overall onshore rig count has increased every year since 2007 when horizontal rigs represented only approximately 25% of the total U.S. onshore rig count at year-end. As a result of improvements in drilling and production enhancement technologies, oil and natural gas companies are increasingly developing unconventional resources such as tight sands and shales. Successful and economic production of these unconventional resource plays frequently requires horizontal drilling, fracturing and stimulation services. Drilling related activity for unconventional resources is typically done on tighter acre spacing and thus requires that more wells be drilled relative to conventional resources. We believe that all of these characteristics will drive the demand for our services in an improved commodity price environment.
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Tight oil production growth is expected to continue to be the primary driver of U.S. oil production growth.
According to the EIA, U.S. tight oil production grew from approximately 430,000 barrels per day in 2007 to over 4.6 million barrels per day in 2017, representing approximately 50% of total U.S. crude oil production in 2017. A majority of this increase came from the Eagle Ford play in South Texas, the SCOOP/STACK plays in the mid-continent of Oklahoma, the Bakken Shale in the Williston Basin of North Dakota and Montana, and the Permian Basin in West Texas. We believe the Utica Shale and the Permian Basin, our primary business locations, will be key drivers of U.S. tight oil and natural gas production as those plays are developed further in the coming years due to the favorable well economics in those basins.
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Horizontal wells are heavily dependent on oilfield services.
According to Baker Hughes, as of December 29, 2017, horizontal rigs accounted for approximately 86% of all rigs drilling in the United States, up from 25% at year-end 2007. The scope of services for a horizontal well are greater than for a conventional well. Industry analysts report that the average horsepower, length of the lateral and number of fracture stages has continued to increase since 2008. We believe our commitment to provide services in unconventional plays, such as the Utica Shale and the Permian Basin, provide us the opportunity to compete in those regional markets where the majority of total footage is drilled each year in the United States.
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New and emerging unconventional resource plays.
In addition to the development of existing unconventional resource plays such as the Permian, Utica, Bakken, Eagle Ford, Barnett, Fayetteville, Cotton Valley, Haynesville, Marcellus and Woodford Shales, exploration and production companies continue to find new unconventional resources. These include oil and liquids-based shales in the Cana Woodford, Granite Wash, Niobrara, Woodford and SCOOP/STACK resource plays. In certain cases, exploration and production companies have acquired vast acreage positions in these plays that require them to drill and produce hydrocarbons to hold the leased acreage. We believe these unconventional resource plays will increasingly drive demand for our services as commodity prices continue to recover as they typically require the use of extended reach horizontal drilling, multiple stage fracture stimulation and high pressure completion capabilities. We also believe we are well positioned to expand our services in two major unconventional plays, the Utica Shale in Ohio and the Permian Basin in West Texas.
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Need for additional drilling activity to maintain production levels.
With the increased maturity of the onshore conventional and, in many cases, unconventional resource plays, oil and natural gas production may be characterized as having steeper initial decline curves. Given average decline rates and the substantial reduction in activity over the past year, we believe that the number of wells drilled is likely to increase in coming years as commodity prices continue to recover. Once a well has been drilled, it requires recurring production and completion services, which we believe will also drive demand for our services.
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improvements in drilling rig productivity (from, among other things, pad drilling), resulting in more wells drilled per rig per year;
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increases in the number of wells drilled per acre;
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increases in the length of the typical horizontal wellbore;
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increases in the number of fracture stages per lateral foot in the typical completed horizontal wellbore;
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increases in the volume of proppant used per fracturing stage; and
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recurring efforts to offset steep production declines in unconventional oil and natural gas reservoirs, including the drilling of new wells and secondary hydraulic fracturing of existing wells.
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the difficulty of finding frac sand reserves that meet API specifications and consisting of the mesh size in demand;
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the difficulty of securing contiguous frac sand reserves large enough to justify the capital investment required to develop a processing facility with a higher base of fixed costs;
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the challenges of identifying frac sand reserves with the above characteristics that either are located in close proximity to oil and natural gas reservoirs or have rail access needed for low-cost transportation to major shale basins;
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the hurdles of securing mining, production, water, air, refuse and other federal, state and local operating permits from the proper authorities;
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local opposition to development of facilities, especially those that require the use of on-road transportation, including hours of operations and noise level restrictions, in addition to moratoria on raw frac sand facilities in multiple counties in Wisconsin and other states which hold potential sand reserves; and
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the typically long lead time required to design and construct sand processing facilities that can efficiently process large quantities of high quality frac sand.
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Modern fleet of hydraulic fracturing equipment designed for horizontal wells
. Our service fleet is predominantly comprised of equipment designed to optimize recovery from unconventional wells. Three of our pressure pumping fleets with total combined horsepower of 132,500 were built in 2017 and our other three fleets with a total combined
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Strategic geographic positioning, including primary presence in the Utica Shale and the Permian Basin.
We currently operate facilities and service centers to support our operations in major unconventional resource plays in the United States, including the Utica Shale in Eastern Ohio, the Permian Basin in West Texas, the SCOOP/STACK in Oklahoma, the Marcellus Shale in West Virginia, the Granite Wash in Oklahoma and Texas, the Cana Woodford Shale and the Cleveland Sand in Oklahoma, the Eagle Ford Shale in South Texas and the oil sands in Alberta, Canada. We believe our geographic positioning within active oil and natural gas liquids resource plays will benefit us strategically as activity increases in these unconventional resource plays.
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Long-term contractual and other regional relationships with a stable customer base.
We are party to two four-year contracts with Gulfport to provide pressure pumping services and natural sand proppant services through September 2018. In addition, our operational division heads and field managers have formed long-term relationships with our customer base. We believe these contractual and other relationships help provide us a more stable and growth-oriented client base in the unconventional shale markets as well as the infrastructure markets that we currently serve. Our customers include large independent oil and natural gas exploration and production companies, government-funded utilities, private utilities, public IOUs and Co-Ops. Our top five customers for the year ended
December 31, 2017
, representing
71%
of our revenue were Gulfport, PREPA, Newfield, Rice Energy and Surge Operating. For the year ended
December 31, 2016
, our top five customers, representing 80% of our revenue, were Gulfport, Oil Sands Limited, Rice Energy, Surge Operating and Hilcorp.
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Experienced management and operating team.
Our operational division heads have an extensive track record in the oilfield and infrastructure service businesses with an average of over 35 years of oilfield services experience and over 25 years of infrastructure services experience. In addition, our field managers have expertise in the areas in which they operate and understand the regional challenges that our customers face. We believe their knowledge of our industries and business lines enhances our ability to provide innovative, client-focused and basin-specific customer service, which we also believe strengthens our relationships with our customers.
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Capitalize on the recovery in activity in the unconventional resource plays.
Our oil and natural gas service equipment is designed to provide a broad range of services for unconventional wells, and our operations are strategically located in major unconventional resource plays. During 2017, the posted price for WTI stabilized and increased following the significant declines experienced in 2016. The average price per barrel in 2017 was $50.97 with a low of $42.53 per barrel on June 21, 2017 to a high of $60.42 per barrel on December 29, 2017. If commodity prices stabilize at current levels or recover further, we expect to experience further increase in demand for our services and products. We intend to capitalize on the anticipated increase in activity in these markets and diversify our operations across additional unconventional resource basins. Our core operations are currently focused in the Utica Shale in Ohio, the SCOOP/STACK in Oklahoma and the Permian Basin in West Texas. We intend to continue to strategically deploy assets to these and other unconventional resource basins and will look to capitalize on further growth in emerging unconventional resource plays as they develop.
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Leverage our broad range of services for unconventional wells for cross-selling opportunities.
We offer a complementary suite of services and products. Our pressure pumping and well services activities provide hydraulic fracturing services for unconventional wells. Our infrastructure services division provides construction, upgrade,
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Expand through selected, accretive acquisitions.
To complement our organic growth, we intend to actively pursue selected, accretive acquisitions of businesses and assets, primarily related to our completion and production services, infrastructure services and natural sand proppant services, that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence. We believe this strategy will facilitate the continued expansion of our customer base, geographic presence and service offerings. We also believe that our industry contacts and those of Wexford, our equity sponsor and largest stockholder, may be helpful to facilitate the identification of acquisition opportunities. We may use our common stock as consideration for accretive acquisitions.
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Maintain a conservative balance sheet.
We seek to maintain a conservative balance sheet, which allows us to better react to changes in commodity prices and related demand for our services, as well as overall market conditions. We used a portion of the net proceeds from the IPO to repay all outstanding borrowings under our revolving credit facility, and as of December 31, 2016, had no outstanding debt. During 2017, we used borrowings under our revolving credit facility to fund
$133.9 million
in capital expenditures and three accretive acquisitions, and as of
December 31, 2017
, had outstanding debt totaling
$99.9 million
and a cash balance of
$5.6 million
. We intend to use a portion of our cash flows from operations to reduce our outstanding debt in 2018.
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Expand our services to meet expanding customer demand.
The scope of services for horizontal wells is greater than that for conventional wells. Industry analysts have reported that the average horsepower required for current completion designs, amount of sand per lateral foot, length of lateral and number of fracture stages has continued to increase since 2008. We consistently monitor market conditions and intend to expand the capacity and scope of our business lines as demand warrants in resource plays in which we currently operate, as well as in new resource plays. If we perceive unmet demand in our principal geographic locations for different service lines, we will seek to expand our current service offerings to meet that demand.
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Expand our energy infrastructure business unit in the Lower 48 and in Puerto Rico.
Industry analysts have reported that spending in the T&D industry will exceed $60 billion each year through 2022. We consistently monitor market conditions and intend to expand the capacity and scope of our energy infrastructure services as demand warrants in geographic areas in which we currently operate, as well as in new geographic areas.
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Leverage our experienced operational management team expertise.
We seek to manage the services we provide as closely as possible to the needs of our customer base. Our operational division heads have long-term relationships with our largest customers. We intend to leverage these relationships and our operational management team’s expertise to deliver innovative, client focused and services to our customers.
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personal injury or loss of life;
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damage or destruction of property, equipment, natural resources and the environment; and
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suspension of operations.
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licensing, permitting and inspection requirements applicable to contractors, electricians and engineers;
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regulations relating to worker safety;
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permitting and inspection requirements applicable to construction projects;
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wage and hour regulations;
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building and electrical codes; and
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special bidding, procurement and other requirements on government projects.
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the location of wells;
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the method of drilling and casing wells;
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the timing of construction or drilling activities, including seasonal wildlife closures;
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the surface use and restoration of properties upon which wells are drilled;
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the plugging and abandoning of wells; and
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notice to, and consultation with, surface owners and other third parties.
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the domestic and foreign supply of and demand for oil and natural gas;
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the level of prices, and expectations about future prices, of oil and natural gas;
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the level of global oil and natural gas exploration and production;
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the cost of exploring for, developing, producing and delivering oil and natural gas;
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the expected decline rates of current production;
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the price and quantity of foreign imports;
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political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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speculative trading in crude oil and natural gas derivative contracts;
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the level of consumer product demand;
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the discovery rates of new oil and natural gas reserves;
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contractions in the credit market;
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the strength or weakness of the U.S. dollar;
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available pipeline and other transportation capacity;
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the levels of oil and natural gas storage;
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weather conditions and other natural disasters;
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political instability in oil and natural gas producing countries;
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domestic and foreign tax policy;
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domestic and foreign governmental approvals and regulatory requirements and conditions;
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the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;
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technical advances affecting energy consumption;
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the proximity and capacity of oil and natural gas pipelines and other transportation facilities;
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the price and availability of alternative fuels;
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the ability of oil and natural gas producers to raise equity capital and debt financing;
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merger and divestiture activity among oil and natural gas producers; and
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overall domestic and global economic conditions.
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weather issues, whether short-term such as a hurricane, or long-term such as a drought; and
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shortage in the number of vendors able or willing to provide the necessary equipment, supplies and materials, including as a result of commitments of vendors to other customers or third parties.
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shortages of equipment, materials or skilled labor;
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unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;
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failure of equipment to meet quality and/or performance standards;
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financial or operating difficulties of equipment vendors;
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unanticipated actual or purported change orders;
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inability by us or our customers to obtain required permits or approvals, or to meet applicable regulatory standards in our areas of operations;
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unanticipated cost increases between order and delivery;
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adverse weather conditions and other events of force majeure;
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design or engineering changes; and
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work stoppages and other labor disputes.
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have sufficient capital resources to build new, technologically advanced equipment and other assets;
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successfully integrate additional oilfield service equipment and other assets;
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effectively manage the growth and increased size of our organization, equipment and other assets;
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successfully deploy idle, stacked or additional oilfield service assets;
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maintain crews necessary to operate additional drilling rigs or pressure pumping service equipment; or
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successfully improve our financial condition, results of operations, business or prospects.
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geological and mining conditions and/or effects from prior mining that may not be fully identified by available data or that may differ from experience;
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assumptions concerning future prices of frac sand, operating costs, mining technology improvements, development costs and reclamation costs; and
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assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.
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curtailment of services;
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weather-related damage to equipment resulting in suspension of operations;
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weather-related damage to our facilities;
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inability to deliver equipment and materials to jobsites in accordance with contract schedules; and
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loss of productivity.
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•
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unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including but not limited to environmental liabilities;
|
•
|
difficulties in integrating the operations and assets of the acquired business and the acquired personnel;
|
•
|
limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business, in order to comply with public reporting requirements;
|
•
|
potential losses of key employees and customers of the acquired businesses;
|
•
|
inability to commercially develop acquired technologies;
|
•
|
risks of entering markets in which we have limited prior experience; and
|
•
|
increases in our expenses and working capital requirements.
|
•
|
an inability to retain or hire experienced crews and other personnel;
|
•
|
a lack of customer demand for the services we intend to provide;
|
•
|
an inability to secure necessary equipment, raw materials (particularly sand and other proppants) or technology to successfully execute our expansion plans;
|
•
|
shortages of water used in our sand processing operations and our hydraulic fracturing operations;
|
•
|
unanticipated delays that could limit or defer the provision of services by us and jeopardize our relationships with existing customers and adversely affect our ability to obtain new customers for such services; and
|
•
|
competition from new and existing services providers.
|
•
|
increasing our vulnerability to general adverse economic and industry conditions;
|
•
|
the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
|
•
|
our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industries;
|
•
|
any failure to comply with the financial or other covenants of our debt, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;
|
•
|
our level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and
|
•
|
our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.
|
•
|
incurring additional indebtedness;
|
•
|
paying dividends;
|
•
|
creating certain additional liens on our assets;
|
•
|
entering into sale and leaseback transactions;
|
•
|
making investments;
|
•
|
entering into transactions with affiliates;
|
•
|
making material changes to the type of business we conduct or our business structure;
|
•
|
making guarantees;
|
•
|
entering into hedges;
|
•
|
disposing of assets in excess of certain permitted amounts;
|
•
|
merging or consolidating with other entities; and
|
•
|
selling all or substantially all of our assets.
|
•
|
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 industries;
|
•
|
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 change.
|
•
|
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.
|
•
|
Any derivative action or proceeding brought on our behalf;
|
•
|
Any action asserting a claim of breach of fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders;
|
•
|
Any action asserting a claim against us arising pursuant to any provision of the Delaware General Corporation Law; or
|
•
|
Any other action asserting a claim against us that is governed by the internal affairs doctrine.
|
Wet Plant Location
|
|
Annual Rated Plant Capacity
(c)
(Thousands of Tons)
|
|
Taylor in Jackson County, Wisconsin
(a)
|
|
1,470
|
|
Piranha in Barron County, Wisconsin
(b)
|
|
4,704
|
|
Muskie in Pierce County, Wisconsin
|
|
1,314
|
|
Dry Plant Location
|
|
Annual Rated Plant Capacity
(c)
(Thousands of Tons)
|
|
Taylor in Jackson County, Wisconsin
(a)
|
|
876
|
|
Piranha in Barron County, Wisconsin
(b)
|
|
2,102
|
|
Muskie in Pierce County, Wisconsin
|
|
876
|
|
(a)
|
Annual rated production capacity of our Jackson County wet and dry plants will increase to
2.6 million
and
2.2 million
tons per year, respectively, when the expansion of the facility is complete, which is expected to occur in March 2018.
|
(b)
|
We acquired our Barron County plants on May 26, 2017. Annual rated production capacity of our Barron County dry plant will increase to 2.6 million tons per year when certain upgrades to this facility are complete, which is expected to occur in mid-2018.
|
(c)
|
Once the expansion projects mentioned in notes (a) and (b) above are completed, our annual company-wide rated production capacity is expected to be 5.7 million tons per year and our annual company-wide functional production capacity is expected to be 4.4 million tons per year.
|
|
|
Estimated Proven Reserves (Thousands of Tons)
|
|||||||
Mine Location
|
|
December 31, 2017
|
|
December 31, 2016
|
|
December 31, 2015
|
|||
Taylor in Jackson County, Wisconsin
(a)
|
|
25,029
|
|
|
25,844
|
|
|
26,348
|
|
Piranha in Barron County, Wisconsin
(b)
|
|
38,150
|
|
|
N/A
|
|
|
N/A
|
|
Total
|
|
63,179
|
|
|
25,844
|
|
|
26,348
|
|
(a)
|
Prior to our June 5, 2017 Sturgeon acquisition, which included our Taylor facilities, we and Sturgeon were under common control and, as a result, our historical financial information for all periods included in this Annual Report on Form 10-K has been recast to combine Sturgeon's financial results with our financial results as if the acquisition had been effective since Sturgeon commenced operations in September 2014.
|
(b)
|
We acquired our Piranha mine in Barron County on May 26, 2017.
|
Item 5.
|
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
|
2017
|
High
|
Low
|
||||
First Quarter
|
$
|
22.45
|
|
$
|
15.38
|
|
Second Quarter
|
$
|
21.72
|
|
$
|
16.25
|
|
Third Quarter
|
$
|
19.40
|
|
$
|
11.05
|
|
Fourth Quarter
|
$
|
20.89
|
|
$
|
14.49
|
|
2016
|
|
|
||||
Fourth Quarter
(a)
|
$
|
17.25
|
|
$
|
12.48
|
|
|
October 14, 2016
|
December 31, 2016
|
December 31, 2017
|
||||||
Mammoth Energy Service, Inc.
|
$
|
100.00
|
|
$
|
114.63
|
|
$
|
148.04
|
|
S&P 500 Stock Index
|
$
|
100.00
|
|
$
|
104.88
|
|
$
|
125.25
|
|
Dow Jones Industrial Average Market Index
|
$
|
100.00
|
|
$
|
108.96
|
|
$
|
136.28
|
|
PHLX Oil Service Sector Index
|
$
|
100.00
|
|
$
|
111.51
|
|
$
|
90.74
|
|
•
|
Pressure Pumping—March 2012
|
•
|
Logistics—November 2012
|
•
|
Barracuda—October 2014
|
•
|
Pumpdown—January 2015
|
•
|
Mr. Inspections—January 2015
|
•
|
Silverback—June 2016
|
•
|
Mammoth Equipment Leasing—November 2016
|
•
|
Cobra Acquisitions—January 2017
|
•
|
Cobra Energy—January 2017
|
•
|
Higher Power Electrical—April 2017
|
•
|
5 Star Electric—July 2017
|
•
|
Muskie Proppant—September 2011
|
•
|
Piranha Proppant—May 2017
|
•
|
Sturgeon Acquisitions—June 2017
|
•
|
Taylor Frac—June 2017
|
•
|
Taylor Real Estate Investments—June 2017
|
•
|
South River Road—June 2017
|
•
|
Bison Drilling—November 2010
|
•
|
Panther Drilling—December 2012
|
•
|
Bison Trucking—August 2013
|
•
|
White Wing—September 2014
|
•
|
Mako Acquisitions—March 2017
|
•
|
Sand Tiger Lodging—October 2007 (previously included in the Other Energy Services segment)
|
•
|
Redback Energy Services—October 2011 (previously included in the Well Services segment)
|
•
|
Redback Coil Tubing—May 2012 (previously included in the Well Services segment)
|
•
|
Mammoth Energy Partners—June 2016 (previously included in the Well Services segment)
|
•
|
Stingray Energy Services—June 2017
|
•
|
Stingray Cementing—June 2017
|
•
|
Tiger Shark Logistics—October 2017
|
|
Years Ended
|
||||||
|
December 31, 2017
|
|
December 31, 2016
|
||||
Revenue:
|
(in thousands)
|
||||||
Pressure pumping services
|
$
|
279,352
|
|
|
$
|
124,425
|
|
Infrastructure services
|
224,425
|
|
|
—
|
|
||
Natural sand proppant services
|
117,037
|
|
|
38,102
|
|
||
Contract land and directional drilling services
|
50,521
|
|
|
32,043
|
|
||
Other
|
51,728
|
|
|
40,970
|
|
||
Eliminations
|
(31,567
|
)
|
|
(4,915
|
)
|
||
Total revenue
|
691,496
|
|
|
230,625
|
|
||
|
|
|
|
||||
Cost of Revenue:
|
|
|
|
||||
Pressure pumping services (exclusive of depreciation and amortization of $45,381 and $36,938, respectively, for 2017 and 2016)
|
211,236
|
|
|
86,888
|
|
||
Infrastructure services (exclusive of depreciation and amortization of $3,181 and $0, respectively, for 2017 and 2016)
|
121,560
|
|
|
—
|
|
||
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $9,389 and $6,477, respectively, for 2017 and 2016)
|
92,780
|
|
|
32,456
|
|
||
Contract land and directional drilling services (exclusive of depreciation of $19,630 and $21,481, respectively, for 2017 and 2016)
|
46,847
|
|
|
31,840
|
|
||
Other (exclusive of depreciation and amortization of $14,494 and $7,286, respectively, for 2017 and 2016)
|
41,678
|
|
|
26,752
|
|
||
Eliminations
|
(31,532
|
)
|
|
(4,915
|
)
|
||
Total cost of revenue
|
482,569
|
|
|
173,021
|
|
||
Selling, general and administrative expenses
|
49,886
|
|
|
18,048
|
|
||
Depreciation and amortization
|
92,124
|
|
|
72,315
|
|
||
Impairment of long-lived assets
|
4,146
|
|
|
1,871
|
|
||
Operating income (loss)
|
62,771
|
|
|
(34,630
|
)
|
||
Interest expense, net
|
(4,310
|
)
|
|
(4,096
|
)
|
||
Bargain purchase gain
|
4,012
|
|
|
—
|
|
||
Other (expense) income, net
|
(677
|
)
|
|
158
|
|
||
Income (loss) before income taxes
|
61,796
|
|
|
(38,568
|
)
|
||
Provision for income taxes
|
2,832
|
|
|
53,885
|
|
||
Net income (loss)
|
$
|
58,964
|
|
|
$
|
(92,453
|
)
|
|
Years Ended
|
||||||
|
December 31, 2016
|
|
December 31, 2015
|
||||
Revenue:
|
(in thousands)
|
||||||
Pressure pumping services
|
$
|
124,425
|
|
|
$
|
170,618
|
|
Natural sand proppant services
|
38,102
|
|
|
66,057
|
|
||
Contract land and directional drilling services
|
32,043
|
|
|
73,033
|
|
||
Other
|
40,970
|
|
|
64,133
|
|
||
Eliminations
|
(4,915
|
)
|
|
(5,904
|
)
|
||
Total revenue
|
230,625
|
|
|
367,937
|
|
||
|
|
|
|
||||
Cost of Revenue:
|
|
|
|
||||
Pressure pumping services (exclusive of depreciation and amortization of $36,938 and $35,657, respectively, for 2016 and 2015)
|
86,888
|
|
|
132,129
|
|
||
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $6,477 and $6,298, respectively, for 2016 and 2015)
|
32,456
|
|
|
47,497
|
|
||
Contract land and directional drilling services (exclusive of depreciation of $21,481 and $24,585, respectively, for 2016 and 2015)
|
31,840
|
|
|
57,453
|
|
||
Other (exclusive of depreciation and amortization of $7,286 and $7,812, respectively, for 2016 and 2015)
|
26,752
|
|
|
43,512
|
|
||
Eliminations
|
(4,915
|
)
|
|
(5,904
|
)
|
||
Total cost of revenue
|
173,021
|
|
|
274,687
|
|
||
Selling, general and administrative expenses
|
18,048
|
|
|
22,400
|
|
||
Depreciation, depletion, accretion and amortization
|
72,315
|
|
|
74,499
|
|
||
Impairment of long-lived assets
|
1,871
|
|
|
12,124
|
|
||
Operating loss
|
(34,630
|
)
|
|
(15,773
|
)
|
||
Interest expense, net
|
(4,096
|
)
|
|
(5,367
|
)
|
||
Other income (expense), net
|
158
|
|
|
(2,269
|
)
|
||
Loss before income taxes
|
(38,568
|
)
|
|
(23,409
|
)
|
||
Provision (benefit) for income taxes
|
53,885
|
|
|
(1,589
|
)
|
||
Net loss
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2017
|
|
2016
|
|
2015
|
||||||
Net income (loss)
|
$
|
58,964
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
Depreciation, depletion, amortization and accretion
|
92,124
|
|
|
72,315
|
|
|
74,499
|
|
|||
Impairment of long-lived assets
|
4,146
|
|
|
1,871
|
|
|
12,124
|
|
|||
Acquisition related costs
|
2,506
|
|
|
—
|
|
|
—
|
|
|||
One-time IPO compensation charges
|
—
|
|
|
1,201
|
|
|
—
|
|
|||
Equity based compensation
|
3,741
|
|
|
501
|
|
|
—
|
|
|||
Bargain purchase gain
|
(4,012
|
)
|
|
—
|
|
|
—
|
|
|||
Interest income
|
—
|
|
|
—
|
|
|
(98
|
)
|
|||
Interest expense
|
4,310
|
|
|
4,096
|
|
|
5,465
|
|
|||
Other expense (income), net
|
677
|
|
|
(158
|
)
|
|
2,269
|
|
|||
Provision (benefit) for income taxes
|
2,832
|
|
|
53,885
|
|
|
(1,589
|
)
|
|||
Adjusted EBITDA
|
$
|
165,288
|
|
|
$
|
41,258
|
|
|
$
|
70,850
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2017
|
|
2016
|
|
2015
|
||||||
Net income (loss)
|
$
|
11,451
|
|
|
$
|
(4,568
|
)
|
|
$
|
(5,317
|
)
|
Depreciation, depletion, amortization and accretion
|
45,413
|
|
|
37,013
|
|
|
35,729
|
|
|||
Impairment of long-lived assets
|
—
|
|
|
139
|
|
|
1,214
|
|
|||
Acquisition related costs
|
1
|
|
|
—
|
|
|
—
|
|
|||
One-time IPO compensation charges
|
—
|
|
|
102
|
|
|
—
|
|
|||
Equity based compensation
|
1,641
|
|
|
176
|
|
|
—
|
|
|||
Interest expense
|
1,622
|
|
|
599
|
|
|
1,822
|
|
|||
Other expense, net
|
129
|
|
|
27
|
|
|
67
|
|
|||
Provision for income taxes
|
—
|
|
|
—
|
|
|
72
|
|
|||
Adjusted EBITDA
|
$
|
60,257
|
|
|
$
|
33,488
|
|
|
$
|
33,587
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2017
|
|
2016
|
|
2015
|
||||||
Net income
|
$
|
48,537
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Depreciation, depletion, amortization and accretion
|
3,185
|
|
|
—
|
|
|
—
|
|
|||
Acquisition related costs
|
98
|
|
|
—
|
|
|
—
|
|
|||
Equity based compensation
|
345
|
|
|
—
|
|
|
—
|
|
|||
Interest expense
|
241
|
|
|
—
|
|
|
—
|
|
|||
Other expense, net
|
6
|
|
|
—
|
|
|
—
|
|
|||
Provision for income taxes
|
29,290
|
|
|
—
|
|
|
—
|
|
|||
Adjusted EBITDA
|
$
|
81,702
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2017
|
|
2016
|
|
2015
|
||||||
Net (loss) income
|
$
|
9,474
|
|
|
$
|
(4,709
|
)
|
|
$
|
5,936
|
|
Depreciation, depletion, amortization and accretion
|
9,394
|
|
|
6,483
|
|
|
6,306
|
|
|||
Impairment of long-lived assets
|
324
|
|
|
—
|
|
|
1,905
|
|
|||
Acquisition related costs
|
2,163
|
|
|
—
|
|
|
—
|
|
|||
One-time IPO compensation charges
|
—
|
|
|
33
|
|
|
—
|
|
|||
Equity based compensation
|
708
|
|
|
57
|
|
|
—
|
|
|||
Bargain purchase gain
|
(4,012
|
)
|
|
—
|
|
|
—
|
|
|||
Interest income
|
—
|
|
|
—
|
|
|
(98
|
)
|
|||
Interest expense
|
679
|
|
|
434
|
|
|
225
|
|
|||
Other expense, net
|
211
|
|
|
96
|
|
|
22
|
|
|||
(Benefit) provision for income taxes
|
(4
|
)
|
|
4
|
|
|
—
|
|
|||
Adjusted EBITDA
|
$
|
18,937
|
|
|
$
|
2,398
|
|
|
$
|
14,296
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2017
|
|
2016
|
|
2015
|
||||||
Net loss
|
$
|
(27,244
|
)
|
|
$
|
(30,358
|
)
|
|
$
|
(30,401
|
)
|
Depreciation, depletion, amortization and accretion
|
19,635
|
|
|
21,512
|
|
|
24,627
|
|
|||
Impairment of long-lived assets
|
3,822
|
|
|
347
|
|
|
8,917
|
|
|||
Acquisition related costs
|
8
|
|
|
—
|
|
|
—
|
|
|||
One-time IPO compensation charges
|
—
|
|
|
964
|
|
|
—
|
|
|||
Equity based compensation
|
507
|
|
|
110
|
|
|
—
|
|
|||
Interest expense
|
1,695
|
|
|
2,829
|
|
|
2,928
|
|
|||
Other expense, net
|
256
|
|
|
248
|
|
|
1,121
|
|
|||
Provision (benefit) for income taxes
|
—
|
|
|
—
|
|
|
(185
|
)
|
|||
Adjusted EBITDA
|
$
|
(1,321
|
)
|
|
$
|
(4,348
|
)
|
|
$
|
7,007
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2017
|
|
2016
|
|
2015
|
||||||
Net income (loss)
|
$
|
16,780
|
|
|
$
|
(52,820
|
)
|
|
$
|
7,962
|
|
Depreciation, depletion, amortization and accretion
|
14,497
|
|
|
7,307
|
|
|
7,838
|
|
|||
Impairment of long-lived assets
|
—
|
|
|
1,385
|
|
|
88
|
|
|||
Acquisition related costs
|
237
|
|
|
—
|
|
|
—
|
|
|||
One-time IPO compensation charges
|
—
|
|
|
102
|
|
|
—
|
|
|||
Equity based compensation
|
539
|
|
|
157
|
|
|
—
|
|
|||
Interest income
|
—
|
|
|
—
|
|
|
—
|
|
|||
Interest expense
|
73
|
|
|
234
|
|
|
490
|
|
|||
Other expense (income), net
|
75
|
|
|
(529
|
)
|
|
1,059
|
|
|||
(Benefit) provision for income taxes
|
(26,454
|
)
|
|
53,881
|
|
|
(1,477
|
)
|
|||
Adjusted EBITDA
|
$
|
5,747
|
|
|
$
|
9,717
|
|
|
$
|
15,960
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Cash and cash equivalents
|
$
|
5,637
|
|
|
$
|
29,239
|
|
Revolving credit facility availability
|
169,233
|
|
|
164,354
|
|
||
Less borrowings
|
(99,900
|
)
|
|
—
|
|
||
Less letter of credit facilities (environmental remediation)
|
(3,582
|
)
|
|
(1,375
|
)
|
||
Less letter of credit facilities (insurance programs)
|
(2,486
|
)
|
|
(1,636
|
)
|
||
Less letter of credit facilities (rail car commitments)
|
(455
|
)
|
|
(455
|
)
|
||
Net working capital (less cash)
|
88,798
|
|
|
30,453
|
|
||
Total
|
$
|
157,245
|
|
|
$
|
220,580
|
|
|
Years Ended December 31,
|
||||||||
|
2017
|
2016
|
2015
|
||||||
Net cash provided by operating activities
|
$
|
57,616
|
|
$
|
29,689
|
|
$
|
69,639
|
|
Net cash used in investing activities
|
(172,283
|
)
|
(7,718
|
)
|
(27,035
|
)
|
|||
Net cash provided by (used in) financing activities
|
91,049
|
|
3,075
|
|
(55,557
|
)
|
|||
Effect of foreign exchange rate on cash
|
16
|
|
154
|
|
(227
|
)
|
|||
Net change in cash
|
$
|
(23,602
|
)
|
$
|
25,200
|
|
$
|
(13,180
|
)
|
|
Years Ended December 31,
|
||||||||
|
2017
|
2016
|
2015
|
||||||
Pressure pumping services
(a)
|
$
|
85,853
|
|
$
|
7,673
|
|
$
|
4,170
|
|
Infrastructure services
(b)
|
20,144
|
|
—
|
|
—
|
|
|||
Natural sand proppant services
(c)
|
16,376
|
|
528
|
|
2,371
|
|
|||
Contract and directional drilling services
(d)
|
8,927
|
|
2,710
|
|
12,651
|
|
|||
Other
(e)
|
2,553
|
|
829
|
|
9,260
|
|
|||
Total capital expenditures
|
$
|
133,853
|
|
$
|
11,740
|
|
$
|
28,452
|
|
|
Total
|
|
Less than 1 year
|
|
1-3 Years
|
|
3-5 Years
|
|
More than 5 Years
|
||||||||||
Contractual obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt
(1)
|
$
|
99,900
|
|
|
$
|
—
|
|
|
$
|
99,900
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest and commitment fees on long-term debt
(2)
|
8,738
|
|
|
4,602
|
|
|
4,136
|
|
|
—
|
|
|
—
|
|
|||||
Capital lease and equipment financing obligations
(3)
|
4,012
|
|
|
1,052
|
|
|
2,234
|
|
|
726
|
|
|
—
|
|
|||||
Operating lease obligations
(4)
|
65,634
|
|
|
20,407
|
|
|
26,064
|
|
|
15,818
|
|
|
3,345
|
|
|||||
Purchase commitments
(5)
|
43,088
|
|
|
32,222
|
|
|
10,866
|
|
|
—
|
|
|
—
|
|
|||||
Capital purchase commitments
(6)
|
19,582
|
|
|
19,582
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
$
|
240,954
|
|
|
$
|
77,865
|
|
|
$
|
143,200
|
|
|
$
|
16,544
|
|
|
$
|
3,345
|
|
(1)
|
The long-term debt excludes interest payments.
|
(2)
|
Assumption of long-term debt balance outstanding as of
December 31, 2017
of
$99.9 million
using the weighted average interest rate as of
December 31, 2017
of
4.37%
.
|
(3)
|
Capital lease and equipment financing obligations relate to vehicles and other equipment.
|
(4)
|
Operating lease obligations primarily relate to rail cars, real estate and other equipment.
|
(5)
|
Purchase commitments are comprised of $29.7 million for our sand segment, primarily related to annual obligations to purchase minimum amounts of sand, and $13.4 million for our infrastructure segment, primarily related to lodging service obligations.
|
(6)
|
Obligations arising from capital improvements/equipment purchases.
|
Year ended December 31:
|
Operating Leases
|
|
Capital Spend Commitments
|
|
Minimum Purchase Commitments
|
||||||
2018
|
$
|
20,407
|
|
|
$
|
19,582
|
|
|
$
|
32,222
|
|
2019
|
14,200
|
|
|
—
|
|
|
10,866
|
|
|||
2020
|
11,864
|
|
|
—
|
|
|
—
|
|
|||
2021
|
9,303
|
|
|
—
|
|
|
—
|
|
|||
2022
|
6,515
|
|
|
—
|
|
|
—
|
|
|||
Thereafter
|
3,345
|
|
|
—
|
|
|
—
|
|
|||
|
$
|
65,634
|
|
|
$
|
19,582
|
|
|
$
|
43,088
|
|
Name
|
|
Age
|
|
Position
|
|
Arty Straehla
|
|
64
|
|
|
Chief Executive Officer and Director
|
Mark Layton
|
|
43
|
|
|
Chief Financial Officer and Secretary
|
Marc McCarthy
|
|
47
|
|
|
Chairman of the Board
|
Paul Heerwagen
|
|
33
|
|
|
Director
|
James Palm
|
|
73
|
|
|
Director
|
Matthew Ross
|
|
64
|
|
|
Director
|
Arthur Smith
|
|
65
|
|
|
Director
|
Committee
|
|
Members
|
|
Principal Functions
|
Audit
|
|
Arthur Smith * James Palm Matthew Ross
|
|
-Reviews and discusses with management and the independent auditors the integrity of our accounting policies, internal controls, financial statements, accounting and auditing processes and risk management compliance.
-Monitors and oversees our accounting, auditing and financial reporting processes generally, including the qualifications, independence and performance of the independent auditor.
-Monitors our compliance with legal and regulatory requirements.
-Establishes procedures for the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls or auditing matters, and the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters.
-Reviews and approves related party transactions.
-Appoints, determines compensation, evaluates and terminates our independent auditors.
-Pre-approves audit and permissible non-audit services to be performed by the independent auditors.
-Prepares the report required by the SEC for the inclusion in our annual proxy statement.
|
Compensation
|
|
Marc McCarthy * Paul Heerwagen
Arthur Smith
James Palm
|
|
-Oversees and administers our executive compensation policies, plans and practices and evaluates their impact on risk and risk management.
-Discharges the board of directors’ responsibilities relating to the compensation of our chief executive officer and other executive officers.
-Administers our equity-based compensation plans, including the grants equity awards under such plans.
-Makes recommendations to the board with respect to director compensation.
-Conducts annual performance evaluation of the committee.
-Reviews disclosure related to executive compensation in our proxy statement.
|
*Committee Chairperson
|
|
|
•
|
designing competitive total compensation programs to enhance our ability to attract and retain knowledgeable and experienced senior management level employees;
|
•
|
motivating employees to deliver outstanding financial performance and meet or exceed general and specific business, operational and individual objectives;
|
•
|
setting compensation and incentive levels relevant to the market in which the employee provides service; and
|
•
|
providing a meaningful portion of the total compensation to our named executive officers in equity, thus assuring an alignment of interests between our senior management level employees and our stockholders.
|
•
|
the individual’s particular background and circumstances, including training and prior relevant work experience;
|
•
|
the individual’s role with us and the compensation paid to similar persons at comparable companies;
|
•
|
the demand for individuals with the individual’s specific expertise and experience at the time of hire;
|
•
|
achievement of individual and company performance goals and other expectations relating to the position;
|
•
|
comparison to other executives within our company having similar levels of expertise and experience and the uniqueness of the individual’s industry skills; and
|
•
|
aligning the compensation of our executives with the performance of our company on both a short-term and long-term basis.
|
Plan Category
|
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
|
|
Weighted-average exercise price of outstanding options, warrants and rights
|
|
Number of securities remaining available for future issuance under equity compensation plans
|
||
Equity compensation plans approved by security holders
(1)
|
|
|
|
|
|
|
||
Equity Incentive Plan
|
|
636,805
|
|
|
N/A
|
|
3,756,109
|
|
(1)
|
Our board of directors adopted, and our stockholders approved, our equity incentive plan in connection with and prior to our IPO.
|
Name and Principal Position
|
|
Year
|
|
Salary ($)
|
|
Bonus
(1)
($)
|
|
Stock Awards
(2)
($)
|
|
All Other Compensation
(3)
($)
|
|
Total ($)
|
||||||||||
Arty Straehla, Chief Executive Officer
|
|
2017
|
|
$
|
600,000
|
|
|
$
|
400,000
|
|
|
$
|
—
|
|
|
$
|
27,264
|
|
|
$
|
1,027,264
|
|
|
|
2016
|
|
$
|
400,770
|
|
|
$
|
—
|
|
|
$
|
3,750,000
|
|
|
$
|
—
|
|
|
$
|
4,150,770
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Mark Layton, Chief Financial Officer
|
|
2017
|
|
$
|
300,000
|
|
|
$
|
200,000
|
|
|
$
|
847,200
|
|
|
$
|
—
|
|
|
$
|
1,347,200
|
|
|
|
2016
|
|
$
|
221,626
|
|
|
$
|
350,000
|
|
|
$
|
225,000
|
|
|
$
|
—
|
|
|
$
|
796,626
|
|
(1)
|
The amount awarded to Mr. Layton for 2016 consists of a discretionary bonus of $50,000 and a one-time bonus of $300,000 awarded in connection with the successful completion of our IPO. The amount awarded to Mr. Layton for 2017 consists of a cash bonus of $200,000. The amount awarded to Mr. Straehla for 2017 consists of a cash bonus of $400,000.
|
(2)
|
The amounts shown reflect the grant date fair value of restricted stock units granted determined in accordance with FASB ASC Topic 718. See Note 13 to our consolidated financial statements included elsewhere in this report. Details regarding equity awards that are still outstanding can be found in the “Outstanding Equity Awards at Fiscal 2017 Year End” table.
|
(3)
|
Consists of $27,264 attributable to sporting event tickets.
|
Name and Principal Position
|
|
Grant Date
|
|
Share Price At Grant Date ($)
|
|
Number of Shares or Units of Stock That Have Not Vested (#)
|
|
Market Value of Shares of Stock That Have Not Vested
(1)
($)
|
|||||
Arty Straehla, Chief Executive Officer
(2)
|
|
10/19/2016
|
|
$
|
15.00
|
|
|
166,667
|
|
|
$
|
3,271,673
|
|
|
|
|
|
|
|
|
|
|
|||||
Mark Layton, Chief Financial Officer
(3)
|
|
10/19/2016
|
|
$
|
15.00
|
|
|
11,250
|
|
|
$
|
220,838
|
|
|
|
2/21/2017
|
|
$
|
21.18
|
|
|
40,000
|
|
|
$
|
785,200
|
|
(1)
|
Market value of shares or units that have not vested is based on the closing price of $19.63 per share of our common stock on The Nasdaq Global Select Market on December 29, 2017, the last trading day of 2017.
|
(2)
|
These restricted stock units vest in two remaining approximately equal annual installments beginning on October 19, 2018.
|
(3)
|
Restricted stock units granted on October 19, 2016 vest in three remaining approximately equal annual installments beginning on October 19, 2018. Restricted stock units granted on February 21, 2017 vest in three approximately equal annual installments beginning on February 21, 2018.
|
Name
|
|
Board & Committee Retainer Fees
|
|
Meeting Fees
|
|
Stock Awards
(1)
($)
|
|
All Other Compensation ($)
|
|
Total ($)
|
||||||||||
Marc McCarthy
(2)
|
|
$
|
20,417
|
|
|
$
|
4,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24,917
|
|
Paul Heerwagen
(3)
|
|
$
|
10,417
|
|
|
$
|
10,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
20,417
|
|
Arthur Smith
|
|
$
|
22,917
|
|
|
$
|
21,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44,417
|
|
André Weiss
|
|
$
|
6,250
|
|
|
$
|
25,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
31,750
|
|
Matthew Ross
|
|
$
|
20,417
|
|
|
$
|
28,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
48,917
|
|
James Palm
|
|
$
|
31,966
|
|
|
$
|
4,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
35,966
|
|
(1)
|
As of December 31, 2017, Messrs. McCarthy, Heerwagen, Smith and Ross each had unvested awards of 2,222 restricted stock units outstanding, which will vest on October 19, 2018. Mr. Weiss forfeited 4,444 unvested awards of restricted stock units granted to him in connection with our IPO in October 2016 upon his resignation from our board of directors in June 2017. The Stock Awards column excludes 2,913, 2,913, 2,913, 2,913 and 4,370 restricted stock units granted to Mr. McCarthy, Mr. Heerwagen, Mr. Smith, Mr. Ross and Mr. Palm, respectively, on February 2, 2018, with a value of $63,562 in the case of each of Mr. McCarthy, Mr. Heerwargen, Mr. Smith and Mr. Ross and $95,343 in the case of Mr. Palm (based on the closing price per share of our common stock of $21.82 on February 2, 2018). These February 2018 grants were made to transition the grant date for the annual equity awards for our non-employee directors from the anniversary date of our IPO to the date of our annual meeting of stockholders and cover the partial service period beginning on October 20, 2017 and ending on June 8, 2018 for each such director, except Mr. Palm, who received his grant for the service period beginning on June 26, 2017, the date he joined our board of directors,
|
(2)
|
As required under the terms of his employment with Wexford, Mr. McCarthy’s restricted stock units earned in his capacity as a member of our board of directors were assigned to Wexford.
|
(3)
|
As required under the terms of his employment with Gulfport, Mr. Heerwagen’s restricted stock units earned in his capacity as a member of our board of directors were assigned to Gulfport.
|
Name and Address of Beneficial Owner
(1)
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Class
|
|
Mammoth Energy Holdings LLC
|
|
25,013,764
(2)
|
|
56.1
|
%
|
c/o Wexford Capital LP
|
|
|
|
|
|
411 West Putnam Avenue
|
|
|
|
|
|
Greenwich, CT 06830
|
|
|
|
|
|
Gulfport Energy Corporation
|
|
11,176,332
(3)
|
|
25.1
|
%
|
3001 Quail Springs Parkway
|
|
|
|
|
|
Oklahoma City, OK 73134
|
|
|
|
|
|
Janus Henderson Group PLC
|
|
2,528,488
(4)
|
|
5.7
|
%
|
201 Bishopsgate EC2M 3AE
|
|
|
|
|
|
United Kingdom
|
|
|
|
|
(1)
|
Beneficial ownership is determined in accordance with SEC rules. The percentage of shares beneficially owned is based on 44,589,306 shares of common stock outstanding as of February 10, 2018.
|
(2)
|
Based solely on Schedule 13G/A filed jointly with the SEC on February 14, 2018 by MEH Sub LLC (“MEH”), Wexford Capital, Wexford GP LLC (“Wexford GP”), Charles E. Davidson (“Mr. Davidson”) and Joseph M. Jacobs (“Mr. Jacobs”). MEH is a company managed by Wexford. Wexford is an investment advisor registered with the SEC which manages MEH. Wexford GP is the general partner of Wexford. Mr. Davidson and Mr. Jacobs are the managing members of Wexford GP. MEH has shared voting and dispositive power over 25,009,319 shares of common stock. Wexford, Wexford GP, Mr. Davidson and Mr. Jacobs have shared voting and dispositive power over 25,013,764 shares of common stock. Wexford may, by reason of its status as manager of MEH, be deemed to own beneficially the securities of which MEH possesses beneficial ownership. Wexford GP may, as the General Partner of Wexford, be deemed to own beneficially the securities of which MEH possesses beneficial ownership. Each of Mr. Davidson and Mr. Jacobs may, by reason of his status as a controlling person of Wexford GP, be deemed to own beneficially the securities of which MEH possess beneficial ownership. Each of Wexford, Wexford GP, Davidson and Jacobs share the power to vote and to dispose of the securities beneficially owned by MEH. Each of Wexford, Wexford GP, Mr. Davidson and Mr. Jacobs disclaim beneficial ownership of the securities owned by MEH except, in the case of Mr. Davidson and Mr. Jacobs, to the extent of their respective interests in the members of MEH.
|
(3)
|
Based solely on Schedule 13D filed with the SEC on February 14, 2018 by Gulfport, in which it reported sole voting and dispositive power of such shares of common stock.
|
(4)
|
Based solely on Schedule 13G filed with the SEC on February 13, 2018 by Janus Henderson Group PLC, or Janus Henderson. Janus Henderson reported shared voting power and shared dispositive power over 2,528,488 shares of common stock. Janus Henderson has an indirect 97.11% ownership stake in Intech Investment Management LLC (“Intech”) and a 100% ownership stake in Janus Capital Management LLC (“Janus Capital”), Perkins Investment Management LLC (“Perkins”), Geneva Capital Management LLC (“Geneva”), Henderson Global Investors Limited (“HGIL”), Janus Henderson Investors Australia Institutional Funds Management Limited (“HGIAIFML”) and Henderson Global Investors North America Inc (“HGINA”), (each an “Asset Manager” and collectively as the “Asset Managers”). Due to the above ownership structure, holdings for the Asset Managers are aggregated for purposes of this table. Each Asset Manager is an investment adviser registered or authorized in its relevant jurisdiction and each furnishing investment advice to various fund, individual and/or institutional clients (collectively referred to herein as “Managed Portfolios”). As a result of its role as investment adviser or sub-adviser to the Managed Portfolios, Janus Capital may be deemed to be the beneficial owner of 19,400 shares or 0.0% of the shares of outstanding common stock. Janus Capital disclaims any ownership associated with such rights. As a result of its role as investment adviser or sub-adviser to the Managed Portfolios, Perkins may be deemed to be the beneficial owner of 2,509,088 shares or 5.6% of the shares of outstanding common stock. Perkins disclaims any ownership associated with such rights.
|
Name of Beneficial Owner
(1)
|
|
Amount and Nature of Beneficial Ownership
|
|
Percent of Class
|
|
Marc McCarthy
(2)
|
|
—
|
|
|
*
|
Arty Straehla
(3)
|
|
59,283
|
|
|
*
|
Paul Heerwagen
(4)
|
|
—
|
|
|
*
|
Arthur Smith
(5)
|
|
10,445
|
|
|
*
|
Matthew Ross
(6)
|
|
4,445
|
|
|
*
|
James Palm
(7)
|
|
12,700
|
|
|
*
|
Mark Layton
(8)
|
|
19,159
|
|
|
*
|
Directors and Executive Officers as a Group (7 persons)
|
|
106,032
|
|
|
*
|
(1)
|
Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, shares of common stock subject to any options or restricted stock units held by that person that are exercisable or vested as of February 10, 2018, or exercisable or vesting within 60 days of February 10, 2018, are deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 44,589,306 shares of common stock outstanding as of February 10, 2018. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options and the vesting of restricted stock units that are not exercisable and/or vested as of February 10, 2018 or within 60 days of February 10, 2018.
|
(2)
|
Excludes (i) 4,445 shares of common stock, (ii) 2,222 restricted stock units granted under our equity incentive plan, which will vest on October 19, 2018 and (iii) 2,913 restricted stock units granted under our equity incentive plan, which will vest on the earlier of June 8, 2018 and the date of the 2018 annual meeting, all of which were assigned to Wexford under the terms of Mr. McCarthy's employment with Wexford. As a result, Mr. McCarthy disclaims beneficial ownership of these shares of common stock and restricted stock units, except to the extent of any pecuniary interest therein.
|
(3)
|
1,792 of these securities are held in three custodial accounts for the benefit of three of Mr. Straehla’s grandchildren and for which Mr. Straehla maintains investment control. Excludes 166,667 restricted stock units granted under our equity incentive plan, which will vest in two approximately equal annual installments beginning on October 19, 2018.
|
(4)
|
Excludes (i) 2,222 shares of common stock, (ii) 2,222 restricted stock units granted to under our equity incentive plan, which will vest on October 19, 2018 and (iii) 2,913 restricted stock units granted under our equity incentive plan, which will vest on the earlier of June 8, 2018 and the date of the 2018 annual meeting, all of which were assigned to Gulfport under the terms of Mr. Heerwagen's employment with Gulfport. As a result, Mr. Heerwagen disclaims beneficial ownership of these shares of common stock and restricted stock units.
|
(5)
|
Excludes (i) 2,222 restricted stock units granted under our equity incentive plan, which will vest on October 19, 2018, and (ii) 2,913 restricted stock units granted under our equity incentive plan, which will vest on the earlier of June 8, 2018 and the date of the 2018 annual meeting. Includes 6,000 shares of common stock held by Arthur L. Smith Family LP, which is managed by Arthur L. Smith Management LLC, of which Mr. Smith is the manager.
|
(6)
|
Excludes (i) 2,222 restricted stock units granted under our equity incentive plan, which will vest on October 19, 2018, and (ii) 2,913 restricted stock units granted under our equity incentive plan, which will vest on the earlier of June 8, 2018 and the date of the 2018 annual meeting.
|
(7)
|
Excludes 4,370 restricted stock units granted under our equity incentive plan, which will vest on the earlier of June 8, 2018 and the date of the 2018 annual meeting.
|
(8)
|
Excludes (i) 11,250 restricted stock units granted under our equity incentive plan, which will vest in three approximately equal annual installments beginning on October 19, 2018, and (ii) 26,666 restricted stock units granted under our equity incentive plan, which will vest in two remaining approximately equal annual installments beginning on February 21, 2019.
|
•
|
Audit Fees - aggregate fees for audit services, which relate to the fiscal year consolidated audit and quarterly reviews, were $1.1 million in 2017 and $1.0 million in 2016.
|
•
|
Audit-Related Fees - aggregate fees for audit-related services, which relate to registration statements and comfort letters, were $0.3 million in 2017 and $0.5 million in 2016.
|
•
|
Tax Fees- aggregate fees for tax services, consisting of tax return compliance, tax advice and tax planning, were zero in 2017 and $5,000 in 2016.
|
•
|
All Other Fees - aggregate fees for all other services, were zero in 2017 and 2016.
|
Exhibit Number
|
|
Exhibit Description
|
||
2.1#
|
|
Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Rhino Exploration LLC, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 (incorporated by reference to Exhibit A-1 to the Company’s Definitive Schedule 14C, filed with the SEC on May 15, 2017).
|
||
2.2#
|
|
Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 (incorporated by reference to Exhibit A-2 to the Company’s Definitive Schedule 14C, filed with the SEC on May 15, 2017).
|
||
2.3#
|
|
Amended and Restated Contribution Agreement by and among MEH Sub LLC, Gulfport Energy Corporation, Mammoth Energy Partners LLC and Mammoth Energy Services, Inc. dated as of May 12, 2017 (incorporated by reference to Exhibit A-3 to the Company’s Definitive Schedule 14C, filed with the SEC on May 15, 2017).
|
||
2.4#
|
|
Purchase and Sale Agreement, dated as of March 27, 2017, by and between Mammoth Energy Services, Inc., as purchaser, and Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, as sellers (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on May 15, 2017).
|
||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
|
||||
101.INS*
|
|
XBRL Instance Document.
|
||
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
||
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
||
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.
|
|
||
**
|
Furnished herewith, not filed.
|
|
||
+
|
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.
|
|||
##
|
Confidential treatment with respect to certain portions of this agreement was granted by the SEC which portions have been omitted and filed separately with the SEC.
|
|
|
|
|
|
MAMMOTH ENERGY SERVICES, INC.
|
Date:
|
February 28, 2018
|
|
By:
|
|
/s/ Mark Layton
|
|
|
|
|
|
Mark Layton
|
|
|
|
|
|
Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
Signature
|
Title
|
Date
|
/s/ Arty Straehla
|
Chief Executive Officer (principal executive officer) and Director
|
February 28, 2018
|
Arty Straehla
|
|
|
|
|
|
/s/ Mark Layton
|
Chief Financial Officer (principal financial and accounting officer)
|
February 28, 2018
|
Mark Layton
|
|
|
|
|
|
/s/ Marc McCarthy
|
Director (Chairman of the Board)
|
February 28, 2018
|
Marc McCarthy
|
|
|
|
|
|
/s/ Paul K. Heerwagen IV
|
Director
|
February 28, 2018
|
Paul K. Heerwagen IV
|
|
|
|
|
|
/s/ Matthew Ross
|
Director
|
February 28, 2018
|
Matthew Ross
|
|
|
|
|
|
/s/ Arthur Smith
|
Director
|
February 28, 2018
|
Arthur Smith
|
|
|
|
|
|
/s/ James Palm
|
Director
|
February 28, 2018
|
James Palm
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2017 (a)
|
|
2016 (b)
|
|
2015 (b)
|
||||||
REVENUE
|
(in thousands, except per share amounts)
|
||||||||||
Services revenue
|
$
|
435,409
|
|
|
$
|
89,643
|
|
|
$
|
172,012
|
|
Services revenue - related parties
|
166,064
|
|
|
107,147
|
|
|
132,553
|
|
|||
Product revenue
|
47,067
|
|
|
8,052
|
|
|
25,190
|
|
|||
Product revenue - related parties
|
42,956
|
|
|
25,783
|
|
|
38,182
|
|
|||
Total revenue
|
691,496
|
|
|
230,625
|
|
|
367,937
|
|
|||
|
|
|
|
|
|
||||||
COST AND EXPENSES
|
|
|
|
|
|
||||||
Services cost of revenue (exclusive of depreciation and amortization of $82,686, $65,705 and $68,054, respectively, for 2017, 2016 and 2015)
|
390,112
|
|
|
140,063
|
|
|
225,944
|
|
|||
Services cost of revenue - related parties (exclusive of depreciation and amortization of $0, $0 and $0, respectively, for 2017, 2016 and 2015)
|
1,408
|
|
|
1,063
|
|
|
1,379
|
|
|||
Product cost of revenue (exclusive of depreciation and amortization of $9,389, $6,477 and $6,298, respectively, for 2017, 2016 and 2015)
|
91,049
|
|
|
31,892
|
|
|
47,364
|
|
|||
Product cost of revenue - related parties (exclusive of depreciation and amortization of $0, $0 and $0, respectively, for 2017, 2016 and 2015)
|
—
|
|
|
3
|
|
|
—
|
|
|||
Selling, general and administrative
|
48,405
|
|
|
17,290
|
|
|
21,449
|
|
|||
Selling, general and administrative - related parties
|
1,481
|
|
|
758
|
|
|
951
|
|
|||
Depreciation, depletion, amortization and accretion
|
92,124
|
|
|
72,315
|
|
|
74,499
|
|
|||
Impairment of long-lived assets
|
4,146
|
|
|
1,871
|
|
|
12,124
|
|
|||
Total cost and expenses
|
628,725
|
|
|
265,255
|
|
|
383,710
|
|
|||
Operating income (loss)
|
62,771
|
|
|
(34,630
|
)
|
|
(15,773
|
)
|
|||
|
|
|
|
|
|
||||||
OTHER (EXPENSE) INCOME
|
|
|
|
|
|
||||||
Interest income
|
—
|
|
|
—
|
|
|
98
|
|
|||
Interest expense
|
(4,310
|
)
|
|
(4,096
|
)
|
|
(5,465
|
)
|
|||
Bargain purchase gain
|
4,012
|
|
|
—
|
|
|
—
|
|
|||
Other, net
|
(677
|
)
|
|
158
|
|
|
(2,269
|
)
|
|||
Total other expense
|
(975
|
)
|
|
(3,938
|
)
|
|
(7,636
|
)
|
|||
Income (loss) before income taxes
|
61,796
|
|
|
(38,568
|
)
|
|
(23,409
|
)
|
|||
Provision (benefit) for income taxes
|
2,832
|
|
|
53,885
|
|
|
(1,589
|
)
|
|||
Net income (loss)
|
$
|
58,964
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
|
|
|
|
|
|
||||||
OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
||||||
Foreign currency translation adjustment, net of tax of $645, $1,732 and $0, respectively, for 2017, 2016 and 2015
|
555
|
|
|
2,711
|
|
|
(4,815
|
)
|
|||
Comprehensive income (loss)
|
$
|
59,519
|
|
|
$
|
(89,742
|
)
|
|
$
|
(26,635
|
)
|
|
|
|
|
|
|
||||||
Net income (loss) per share (basic) (Note 11)
|
$
|
1.42
|
|
|
$
|
(2.94
|
)
|
|
$
|
(0.73
|
)
|
Net income (loss) per share (diluted) (Note 11)
|
$
|
1.42
|
|
|
$
|
(2.94
|
)
|
|
$
|
(0.73
|
)
|
Weighted average number of shares outstanding (Note 11)
|
41,548
|
|
|
31,500
|
|
|
30,000
|
|
|||
Weighted average number of shares outstanding, including dilutive effect (Note 11)
|
41,639
|
|
|
31,500
|
|
|
30,000
|
|
|||
|
|
|
|
|
|
|
|||||
Pro Forma C Corporation Data (unaudited):
|
|
|
|
|
|
||||||
Net loss, as reported
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
||
Taxes on income earned as a non-taxable entity (Note 10)
|
|
|
15,224
|
|
|
391
|
|
||||
Taxes due to change to C corporation (Note 10)
|
|
|
53,089
|
|
|
—
|
|
||||
Pro forma net loss
|
|
|
$
|
(24,140
|
)
|
|
$
|
(21,429
|
)
|
||
Basic and Diluted (Note 11)
|
|
|
$
|
(0.56
|
)
|
|
$
|
(0.50
|
)
|
||
Weighted average pro forma shares outstanding—basic and diluted (Note 11)
|
|
|
43,107
|
|
|
43,107
|
|
||||
|
|
|
|
|
|
||||||
(a) Financial information includes the results attributable to Sturgeon for the entire period presented. See Note 14.
|
|||||||||||
(b) Financial information has been recast to include results attributable to Sturgeon. See Note 14.
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
|
|
|
|
Retained
|
Additional
|
|
|
|||||||||||||||
|
Common Stock
|
Common
|
Members'
|
Earnings
|
Paid-In
|
|
|
||||||||||||||||
|
Shares
|
Amount
|
Partners
|
Equity
|
(Deficit)
|
Capital
|
AOCI
|
Total
|
|||||||||||||||
|
(in thousands)
|
||||||||||||||||||||||
Balance at January 1, 2015 (a)
|
—
|
|
$
|
—
|
|
$
|
356,322
|
|
$
|
89,274
|
|
$
|
—
|
|
$
|
—
|
|
$
|
(1,112
|
)
|
444,484
|
|
|
Net loss
|
—
|
|
—
|
|
(27,231
|
)
|
5,411
|
|
—
|
|
—
|
|
—
|
|
(21,820
|
)
|
|||||||
Capital distributions
|
—
|
|
—
|
|
(1
|
)
|
(3,901
|
)
|
—
|
|
—
|
|
—
|
|
(3,902
|
)
|
|||||||
Other comprehensive income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(4,815
|
)
|
(4,815
|
)
|
|||||||
Balance at December 31, 2015 (a)
|
—
|
|
—
|
|
329,090
|
|
90,784
|
|
—
|
|
—
|
|
(5,927
|
)
|
413,947
|
|
|||||||
Net loss prior to LLC conversion
|
—
|
|
—
|
|
(32,085
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(32,085
|
)
|
|||||||
Net loss of Sturgeon prior to acquisition
|
—
|
|
—
|
|
—
|
|
(4,045
|
)
|
—
|
|
—
|
|
—
|
|
(4,045
|
)
|
|||||||
Distributions
|
—
|
|
—
|
|
—
|
|
(5,000
|
)
|
—
|
|
—
|
|
—
|
|
(5,000
|
)
|
|||||||
Equity based compensation
|
—
|
|
—
|
|
(19
|
)
|
—
|
|
—
|
|
—
|
|
—
|
|
(19
|
)
|
|||||||
LLC Conversion (Note 1)
|
—
|
|
—
|
|
(296,986
|
)
|
—
|
|
—
|
|
296,986
|
|
—
|
|
—
|
|
|||||||
Issuance of common stock at public offering, net of offering costs
|
37,500
|
|
375
|
|
—
|
|
—
|
|
—
|
|
102,700
|
|
—
|
|
103,075
|
|
|||||||
Stock-based compensation
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
520
|
|
—
|
|
520
|
|
|||||||
Net loss subsequent to LLC conversion
|
—
|
|
—
|
|
—
|
|
—
|
|
(56,323
|
)
|
—
|
|
—
|
|
(56,323
|
)
|
|||||||
Other comprehensive income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2,711
|
|
2,711
|
|
|||||||
Balance at December 31, 2016 (a)
|
37,500
|
|
375
|
|
—
|
|
81,739
|
|
(56,323
|
)
|
400,206
|
|
(3,216
|
)
|
422,781
|
|
|||||||
Net income of Sturgeon prior to acquisition
|
—
|
|
—
|
|
—
|
|
640
|
|
—
|
|
—
|
|
—
|
|
640
|
|
|||||||
Stingray acquisition
|
1,393
|
|
14
|
|
—
|
|
—
|
|
—
|
|
25,748
|
|
—
|
|
25,762
|
|
|||||||
Sturgeon acquisition
|
5,607
|
|
56
|
|
—
|
|
(82,379
|
)
|
—
|
|
78,313
|
|
—
|
|
(4,010
|
)
|
|||||||
Equity based compensation
|
89
|
|
1
|
|
—
|
|
—
|
|
—
|
|
3,743
|
|
—
|
|
3,744
|
|
|||||||
Net income
|
—
|
|
—
|
|
—
|
|
—
|
|
58,324
|
|
—
|
|
—
|
|
58,324
|
|
|||||||
Other comprehensive income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
555
|
|
555
|
|
|||||||
Balance at December 31, 2017
|
44,589
|
$
|
446
|
|
$
|
—
|
|
$
|
—
|
|
$
|
2,001
|
|
$
|
508,010
|
|
$
|
(2,661
|
)
|
$
|
507,796
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
(a) Financial information has been recast to include the financial position and results attributable to Sturgeon. See Note 14.
|
|
Years Ended December 31,
|
||||||||||
|
2017 (a)
|
|
2016 (b)
|
|
2015 (b)
|
||||||
Cash flows from operating activities
|
(in thousands)
|
||||||||||
Net income (loss)
|
$
|
58,964
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
Adjustments to reconcile net income (loss) to cash provided by operating activities:
|
|
|
|
|
|
||||||
Equity based compensation
|
3,741
|
|
|
501
|
|
|
—
|
|
|||
Depreciation, depletion, amortization and accretion
|
92,124
|
|
|
72,315
|
|
|
74,499
|
|
|||
Amortization of coil tubing strings
|
2,855
|
|
|
2,028
|
|
|
2,076
|
|
|||
Amortization of debt origination costs
|
399
|
|
|
603
|
|
|
501
|
|
|||
Bad debt expense
|
16,206
|
|
|
1,968
|
|
|
3,881
|
|
|||
Loss (gain) on disposal of property and equipment
|
69
|
|
|
(702
|
)
|
|
1,429
|
|
|||
Gain on bargain purchase
|
(4,012
|
)
|
|
—
|
|
|
—
|
|
|||
Impairment of long-lived assets
|
4,146
|
|
|
1,871
|
|
|
12,124
|
|
|||
Deferred income taxes
|
(34,425
|
)
|
|
47,899
|
|
|
(5,717
|
)
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable, net
|
(231,751
|
)
|
|
(4,641
|
)
|
|
32,027
|
|
|||
Receivables from related parties
|
(1,096
|
)
|
|
(2,462
|
)
|
|
9,770
|
|
|||
Inventories
|
(14,238
|
)
|
|
(624
|
)
|
|
(3,998
|
)
|
|||
Prepaid expenses and other assets
|
(7,628
|
)
|
|
(198
|
)
|
|
4,287
|
|
|||
Accounts payable
|
101,725
|
|
|
1,412
|
|
|
(30,169
|
)
|
|||
Payables to related parties
|
1,174
|
|
|
(249
|
)
|
|
(756
|
)
|
|||
Accrued expenses and other liabilities
|
32,968
|
|
|
2,420
|
|
|
(8,503
|
)
|
|||
Income taxes payable
|
36,395
|
|
|
1
|
|
|
8
|
|
|||
Net cash provided by operating activities
|
57,616
|
|
|
29,689
|
|
|
69,639
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Purchases of property and equipment
|
(132,295
|
)
|
|
(11,740
|
)
|
|
(28,452
|
)
|
|||
Purchases of property and equipment from related parties
|
(1,558
|
)
|
|
—
|
|
|
—
|
|
|||
Business acquisitions, net
|
(42,008
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from disposal of property and equipment
|
907
|
|
|
4,022
|
|
|
1,417
|
|
|||
Business combination cash acquired (Note 14)
|
2,671
|
|
|
—
|
|
|
—
|
|
|||
Net cash used in investing activities
|
(172,283
|
)
|
|
(7,718
|
)
|
|
(27,035
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Borrowings on long-term debt
|
156,850
|
|
|
28,734
|
|
|
14,571
|
|
|||
Repayments of long-term debt
|
(56,950
|
)
|
|
(123,734
|
)
|
|
(65,612
|
)
|
|||
Proceeds from initial public offering
|
—
|
|
|
105,839
|
|
|
—
|
|
|||
Initial public offering costs
|
—
|
|
|
(2,764
|
)
|
|
—
|
|
|||
Debt issuance costs
|
—
|
|
|
—
|
|
|
(614
|
)
|
|||
Repayment of acquisition-related long-term debt
|
(8,851
|
)
|
|
—
|
|
|
—
|
|
|||
Capital distributions
|
—
|
|
|
(5,000
|
)
|
|
(3,902
|
)
|
|||
Net cash provided by (used in) financing activities
|
91,049
|
|
|
3,075
|
|
|
(55,557
|
)
|
|||
Effect of foreign exchange rate on cash
|
16
|
|
|
154
|
|
|
(227
|
)
|
|||
Net (decrease) increase in cash and cash equivalents
|
(23,602
|
)
|
|
25,200
|
|
|
(13,180
|
)
|
|||
Cash and cash equivalents at beginning of period
|
29,239
|
|
|
4,039
|
|
|
17,219
|
|
|||
Cash and cash equivalents at end of period
|
$
|
5,637
|
|
|
$
|
29,239
|
|
|
$
|
4,039
|
|
|
Years Ended December 31,
|
||||||||||
|
2017 (a)
|
|
2016 (b)
|
|
2015 (b)
|
||||||
Supplemental disclosure of cash flow information:
|
(in thousands)
|
||||||||||
Cash paid for interest
|
$
|
3,656
|
|
|
$
|
3,707
|
|
|
$
|
5,192
|
|
Cash paid for income taxes
|
$
|
840
|
|
|
$
|
3,588
|
|
|
$
|
3,888
|
|
Supplemental disclosure of non-cash transactions:
|
|
|
|
|
|
||||||
Acquisition of Stingray Cementing LLC and Stingray Energy Services LLC
|
$
|
23,091
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Purchases of property and equipment included in accounts payable
|
$
|
15,038
|
|
|
$
|
2,789
|
|
|
$
|
741
|
|
|
|
|
|
|
|
||||||
(a) Financial information includes the results attributable to Sturgeon for the entire period presented. See Note 14.
|
|||||||||||
(b) Financial information has been recast to include results attributable to Sturgeon. See Note 14.
|
1.
|
Organization and Basis of Presentation
|
|
At December 31, 2017
|
|
December 31, 2016
|
||||||||
|
Share Count
|
|
% Ownership
|
|
Share Count
|
|
% Ownership
|
||||
Mammoth Holdings
|
25,009,319
|
|
|
56.1
|
%
|
|
20,443,903
|
|
|
54.5
|
%
|
Gulfport
|
11,171,887
|
|
|
25.1
|
%
|
|
9,073,750
|
|
|
24.2
|
%
|
Rhino
|
568,794
|
|
|
1.3
|
%
|
|
232,347
|
|
|
0.6
|
%
|
Outstanding shares owned by related parties
|
36,750,000
|
|
|
82.5
|
%
|
|
29,750,000
|
|
|
79.3
|
%
|
Total outstanding
|
44,589,306
|
|
|
100.0
|
%
|
|
37,500,000
|
|
|
100.0
|
%
|
2.
|
Summary of Significant Accounting Policies
|
Balance, January 1, 2015
|
|
$
|
590
|
|
Additions charged to expense
|
|
3,881
|
|
|
Deductions for uncollectible receivables written off
|
|
(459
|
)
|
|
Balance, December 31, 2015
|
|
4,012
|
|
|
Additions charged to expense
|
|
1,968
|
|
|
Deductions for uncollectible receivables written off
|
|
(603
|
)
|
|
Balance, December 31, 2016
|
|
5,377
|
|
|
Additions charged to expense
|
|
16,206
|
|
|
Additions - other
|
|
179
|
|
|
Deductions for uncollectible receivables written off
|
|
(25
|
)
|
|
Balance, December 31, 2017
|
|
$
|
21,737
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Balance as of beginning of period
|
|
$
|
260
|
|
|
$
|
95
|
|
Liabilities assumed through acquisition
|
|
1,732
|
|
|
—
|
|
||
Accretion expense
|
|
124
|
|
|
162
|
|
||
Foreign currency translation adjustment
|
|
7
|
|
|
3
|
|
||
Asset retirement obligation as of end of period
|
|
$
|
2,123
|
|
|
$
|
260
|
|
|
REVENUES
|
|
ACCOUNTS RECEIVABLE
|
||||||||
|
Years Ended December 31,
|
|
At December 31,
|
||||||||
|
2017
|
2016
|
2015
|
|
2017
|
2016
|
|||||
Customer A
(a)
|
30
|
%
|
57
|
%
|
46
|
%
|
|
12
|
%
|
57
|
%
|
Customer B
(b)
|
29
|
%
|
—
|
|
—
|
|
|
56
|
%
|
—
|
|
Customer C
(c)
|
1
|
%
|
11
|
%
|
6
|
%
|
|
—
|
|
9
|
%
|
Customer D
(d)
|
—
|
|
—
|
|
12
|
%
|
|
—
|
|
—
|
|
a.
|
Customer A is a related party customer. Revenues and the related accounts receivable balances earned from Customer A were derived from the Company's pressure pumping services segment, natural sand proppant services segment, contract land and directional drilling services segment and other businesses.
|
b.
|
Customer B is a third-party customer. Revenues and the related accounts receivable balances earned from Customer B were derived from the Company's infrastructure services segment.
|
c.
|
Customer C is a third-party customer. Revenues and the related accounts receivable balances earned from Customer C were derived from the Company's remote accommodations business.
|
d.
|
Customer D is a third-party customer. Revenues earned from Customer D were derived from the Company's pressure pumping services segment. No revenues were earned from Customer D during the years ended
December 31, 2017
or
2016
.
|
3.
|
Inventories
|
4.
|
Property, Plant and Equipment
|
|
|
|
December 31,
|
||||||
|
Useful Life
|
|
2017
|
|
2016
|
||||
Pressure pumping equipment
|
3-5 years
|
|
$
|
190,211
|
|
|
$
|
96,501
|
|
Drilling rigs and related equipment
|
3-15 years
|
|
132,260
|
|
|
138,527
|
|
||
Machinery and equipment
(a)
|
7-20 years
|
|
97,569
|
|
|
35,548
|
|
||
Buildings
|
15-39 years
|
|
45,992
|
|
|
54,833
|
|
||
Vehicles, trucks and trailers
(b)
|
5-10 years
|
|
54,055
|
|
|
33,141
|
|
||
Coil tubing equipment
|
4-10 years
|
|
28,053
|
|
|
28,019
|
|
||
Land
|
N/A
|
|
11,317
|
|
|
5,040
|
|
||
Land improvements
|
15 years or life of lease
|
|
9,614
|
|
|
3,641
|
|
||
Rail improvements
|
10-20 years
|
|
5,540
|
|
|
4,277
|
|
||
Other property and equipment
|
3-12 years
|
|
12,687
|
|
|
11,462
|
|
||
|
|
|
587,298
|
|
|
410,989
|
|
||
Deposits on equipment and equipment in process of assembly
|
|
|
20,348
|
|
|
9,427
|
|
||
|
|
|
607,646
|
|
|
420,416
|
|
||
Less: accumulated depreciation, depletion, amortization and accretion
(c)
|
|
|
256,629
|
|
|
178,296
|
|
||
Property, plant and equipment, net
|
|
|
$
|
351,017
|
|
|
$
|
242,120
|
|
a.
|
Included in machinery and equipment are assets under capital leases totaling
$1.8 million
for the year ended
December 31, 2017
.
|
b.
|
Included in vehicles, trucks and trailers are assets under capital leases totaling
$1.0 million
and
$1.1 million
, respectively, for the years ended
December 31, 2017
and
2016
.
|
c.
|
Accumulated depreciation for assets under capital leases totaled
$0.8 million
and
$0.9 million
, respectively, for the years ended
December 31, 2017
and
2016
.
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Depreciation expense
(a)
|
|
$
|
81,191
|
|
|
$
|
62,196
|
|
|
$
|
64,568
|
|
Accretion and depletion expense (see Note 2)
|
|
1,632
|
|
|
1,048
|
|
|
829
|
|
|||
Amortization expense (see Note 6)
|
|
9,301
|
|
|
9,071
|
|
|
9,102
|
|
|||
Depreciation, depletion, amortization and accretion
|
|
$
|
92,124
|
|
|
$
|
72,315
|
|
|
$
|
74,499
|
|
a.
|
Includes depreciation expense for assets under capital leases totaling
$0.4 million
,
$0.5 million
and
$0.6 million
, respectively, for the years ended
December 31, 2017
,
2016
and
2015
.
|
5.
|
Impairments
|
|
December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Flowback equipment
(a)
|
$
|
—
|
|
|
$
|
1,385
|
|
|
$
|
—
|
|
Drilling rigs
(a)
|
3,822
|
|
|
347
|
|
|
8,917
|
|
|||
Fluid storage equipment
(a)
|
—
|
|
|
—
|
|
|
957
|
|
|||
Other property, plant and equipment
(a)
|
324
|
|
|
139
|
|
|
—
|
|
|||
Impairment of long term contractual agreement
(b)
|
—
|
|
|
—
|
|
|
1,905
|
|
|||
Impairment of goodwill
(c)
|
—
|
|
|
—
|
|
|
88
|
|
|||
Impairment of intangible
(d)
|
—
|
|
|
—
|
|
|
257
|
|
|||
|
$
|
4,146
|
|
|
$
|
1,871
|
|
|
$
|
12,124
|
|
a.
|
For the years ended
December 31, 2017
,
2016
and
2015
, the Company recognized impairments of
$4.1 million
,
$1.9 million
and
$9.9 million
, respectively, to reduce the carrying value of certain assets which deemed impaired based on future expected cash flows of the equipment. The Company measured impairment using significant unobservable inputs (Level 3) based on an income approach.
|
b.
|
The Company impaired
$1.9 million
of assets in
2015
related to prepaid assets pursuant to a purchase contract from a vendor.
|
c.
|
The Company determined that there was an indication of impairment present based on the results of the first step of the goodwill impairment test for the goodwill held at Energy Services and
fully impaired
the
$0.1 million
balance
in
2015
.
|
d.
|
The Company
terminated one customer relationship related to its amortizable intangible assets and impaired the remaining unamortized value of the intangible of that relationship
in
2015
.
|
6.
|
Goodwill and Intangible Assets
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Customer relationships
|
|
$
|
35,795
|
|
|
$
|
33,605
|
|
Trade names
|
|
8,793
|
|
|
7,110
|
|
||
Less: accumulated amortization - customer relationships
|
|
(26,172
|
)
|
|
(17,655
|
)
|
||
Less: accumulated amortization - trade names
|
|
(2,277
|
)
|
|
(1,493
|
)
|
||
Intangible assets, net
|
|
$
|
16,139
|
|
|
$
|
21,567
|
|
Year ended December 31:
|
|
Amount
|
||
2018
|
|
$
|
8,578
|
|
2019
|
|
1,096
|
|
|
2020
|
|
1,095
|
|
|
2021
|
|
1,090
|
|
|
2022
|
|
1,068
|
|
|
Thereafter
|
|
3,212
|
|
|
|
|
$
|
16,139
|
|
Balance, January 1, 2016
|
|
$
|
88,727
|
|
Additions
|
|
—
|
|
|
Balance, December 31, 2016
|
|
88,727
|
|
|
Additions - 2017 Stingray Acquisition (Note 14)
|
|
10,193
|
|
|
Additions - Higher Power Acquisition (Note 14)
|
|
643
|
|
|
Additions - 5 Star Acquisition (Note 14)
|
|
248
|
|
|
Balance, December 31, 2017
|
|
$
|
99,811
|
|
7.
|
Accrued Expenses and Other Current Liabilities
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Deferred revenue
|
|
$
|
15,210
|
|
|
$
|
—
|
|
Accrued compensation, benefits and related taxes
|
|
11,552
|
|
|
2,432
|
|
||
Financed insurance premiums
|
|
4,876
|
|
|
3,294
|
|
||
Insurance reserves
|
|
2,942
|
|
|
971
|
|
||
State and local taxes payable
|
|
2,126
|
|
|
320
|
|
||
Other
|
|
4,189
|
|
|
1,529
|
|
||
Total
|
|
$
|
40,895
|
|
|
$
|
8,546
|
|
8.
|
Debt
|
9.
|
Other Liabilities
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Capital lease obligations
|
|
$
|
2,015
|
|
|
$
|
476
|
|
Equipment financing arrangement
|
|
1,605
|
|
|
—
|
|
||
Taxes
|
|
—
|
|
|
2,306
|
|
||
Other
|
|
500
|
|
|
—
|
|
||
Total
|
|
4,120
|
|
|
2,782
|
|
||
Less: Current portion of capital lease and equipment financing obligations included in accrued expenses and other current liabilities
|
|
831
|
|
|
378
|
|
||
Total Other Liabilities
|
|
$
|
3,289
|
|
|
$
|
2,404
|
|
2018
|
$
|
1,052
|
|
2019
|
1,565
|
|
|
2020
|
669
|
|
|
2021
|
366
|
|
|
2022
|
360
|
|
|
Total future minimum payments
|
4,012
|
|
|
Less interest payments
|
(392
|
)
|
|
Present value of future minimum payments
|
$
|
3,620
|
|
10.
|
Income Taxes
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
U.S. current income tax expense
|
|
$
|
804
|
|
|
$
|
2,307
|
|
|
$
|
13
|
|
U.S. deferred income tax (benefit) expense
|
|
(27,764
|
)
|
|
47,957
|
|
|
(5,626
|
)
|
|||
Foreign current income tax expense
|
|
36,565
|
|
|
3,594
|
|
|
3,879
|
|
|||
Foreign deferred income tax (benefit) expense
|
|
(6,773
|
)
|
|
27
|
|
|
145
|
|
|||
Total
|
|
$
|
2,832
|
|
|
$
|
53,885
|
|
|
$
|
(1,589
|
)
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
Income (loss) before income taxes, as reported
|
|
$
|
61,796
|
|
|
$
|
(38,568
|
)
|
|
$
|
(23,409
|
)
|
Bargain purchase gain, net of tax
|
|
(4,012
|
)
|
|
—
|
|
|
—
|
|
|||
Income (loss) before income taxes, as taxed
|
|
57,784
|
|
|
(38,568
|
)
|
|
(23,409
|
)
|
|||
Statutory income tax rate
|
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
|||
Expected income tax expense (benefit)
|
|
20,224
|
|
|
(13,499
|
)
|
|
(8,193
|
)
|
|||
Income earned as non-taxable entity (See Note 2)
|
|
—
|
|
|
15,167
|
|
|
—
|
|
|||
Effect due to change to C corporation (See Note 2)
|
|
—
|
|
|
53,089
|
|
|
—
|
|
|||
Change in entity status
|
|
—
|
|
|
—
|
|
|
(4,792
|
)
|
|||
Non taxable entity
|
|
—
|
|
|
—
|
|
|
13,562
|
|
|||
Change in tax rate
|
|
(21,309
|
)
|
|
(25
|
)
|
|
—
|
|
|||
Tax reform - unrepatriated foreign earnings
|
|
(9,727
|
)
|
|
—
|
|
|
—
|
|
|||
Foreign income tax rate differential
|
|
6,286
|
|
|
(1,078
|
)
|
|
(1,370
|
)
|
|||
Foreign earnings not in reported income
|
|
22,054
|
|
|
—
|
|
|
—
|
|
|||
Foreign tax credits
|
|
(29,551
|
)
|
|
—
|
|
|
—
|
|
|||
Other permanent differences
|
|
503
|
|
|
210
|
|
|
—
|
|
|||
State tax expenses
|
|
39
|
|
|
21
|
|
|
—
|
|
|||
Other
|
|
(1,192
|
)
|
|
—
|
|
|
(796
|
)
|
|||
Change in valuation allowance
|
|
15,505
|
|
|
—
|
|
|
—
|
|
|||
Total
|
|
$
|
2,832
|
|
|
$
|
53,885
|
|
|
$
|
(1,589
|
)
|
|
|
Year Ended December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Deferred tax assets:
|
|
|
|
|
||||
Allowance for doubtful accounts
|
|
$
|
11,973
|
|
|
$
|
1,893
|
|
Deferred compensation
|
|
1,032
|
|
|
1,687
|
|
||
Accrued liabilities
|
|
1,442
|
|
|
601
|
|
||
Foreign tax credits
|
|
15,505
|
|
|
145
|
|
||
Other
|
|
1,448
|
|
|
1,786
|
|
||
Valuation allowance
|
|
(15,505
|
)
|
|
—
|
|
||
Deferred tax assets
|
|
15,895
|
|
|
6,112
|
|
||
|
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
|
||||
Property and equipment
|
|
$
|
(40,390
|
)
|
|
$
|
(42,526
|
)
|
Intangible assets
|
|
(2,839
|
)
|
|
(7,663
|
)
|
||
Unrepatriated foreign earnings
|
|
—
|
|
|
(3,451
|
)
|
||
Other
|
|
(74
|
)
|
|
(143
|
)
|
||
Deferred tax liabilities
|
|
(43,303
|
)
|
|
(53,783
|
)
|
||
Net deferred tax liability
|
|
$
|
(27,408
|
)
|
|
$
|
(47,671
|
)
|
|
|
|
|
|
||||
Reflected in accompanying balance sheet as:
|
|
|
|
|
||||
Deferred income tax asset
|
|
$
|
6,739
|
|
|
$
|
—
|
|
Deferred income tax liability
|
|
(34,147
|
)
|
|
(47,671
|
)
|
||
Total
|
|
$
|
(27,408
|
)
|
|
$
|
(47,671
|
)
|
11.
|
Earnings (Loss) Per Share
|
|
|
2015
|
||
Net loss
|
|
$
|
(21,820
|
)
|
Net loss per limited partner unit
|
|
(0.73
|
)
|
|
Weighted-average common units outstanding
|
|
30,000
|
|
Year Ended December 31,
|
|
Weighted Average Shares Outstanding
|
|
Share Issuance at IPO
(a)
|
|
Conversion
|
|
Weighted Average Units Outstanding
|
||||
2016
|
|
31,500,000
|
|
|
1,500,000
|
|
|
(30,000,000
|
)
|
|
30,000,000
|
|
2015
|
|
30,000,000
|
|
|
—
|
|
|
(30,000,000
|
)
|
|
30,000,000
|
|
(a)
|
Weighted average of
7,500,000
shares issued from the closing date of the IPO on October 19, 2016 to December 31, 2016.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in thousands, except per share data)
|
||||||||||
Basic earnings (loss) per share:
|
|
|
|
|
|
|
||||||
Allocation of earnings:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
58,964
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
Weighted average common shares outstanding
|
|
41,548
|
|
|
31,500
|
|
|
30,000
|
|
|||
Basic earnings (loss) per share
|
|
$
|
1.42
|
|
|
$
|
(2.94
|
)
|
|
$
|
(0.73
|
)
|
|
|
|
|
|
|
|
||||||
Diluted earnings (loss) per share:
|
|
|
|
|
|
|
||||||
Allocation of earnings:
|
|
|
|
|
|
|
||||||
Net income (loss)
|
|
$
|
58,964
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
Weighted average common shares, including dilutive effect
(a)
|
|
41,639
|
|
|
31,500
|
|
|
30,000
|
|
|||
Diluted earnings (loss) per share
|
|
$
|
1.42
|
|
|
$
|
(2.94
|
)
|
|
$
|
(0.73
|
)
|
(a)
|
No
incremental shares of potentially dilutive restricted stock awards were included for the years ended December 31, 2016 or 2015 as their effect was antidilutive under the treasury stock method.
|
|
|
Year Ended December 31,
|
||||||
|
|
2016
|
|
2015
|
||||
|
|
(in thousands, except per share data)
|
||||||
Pro Forma C Corporation Data (unaudited):
|
|
|
|
|
||||
Net loss, as reported
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
Taxes on income earned as a non-taxable entity (Note 10)
|
|
15,224
|
|
|
391
|
|
||
Taxes due to change to C corporation (Note 10)
|
|
53,089
|
|
|
—
|
|
||
Pro forma net loss
|
|
$
|
(24,140
|
)
|
|
$
|
(21,429
|
)
|
|
|
|
|
|
||||
Basic loss per share:
|
|
|
|
|
||||
Allocation of earnings:
|
|
|
|
|
||||
Net loss
|
|
$
|
(24,140
|
)
|
|
$
|
(21,429
|
)
|
Weighted average common shares outstanding
|
|
43,107
|
|
|
43,107
|
|
||
Basic loss per share
|
|
$
|
(0.56
|
)
|
|
$
|
(0.50
|
)
|
|
|
|
|
|
||||
Diluted loss per share:
|
|
|
|
|
||||
Allocation of earnings:
|
|
|
|
|
||||
Net loss
|
|
$
|
(24,140
|
)
|
|
$
|
(21,429
|
)
|
Weighted average common shares, including dilutive effect
(a)
|
|
43,107
|
|
|
43,107
|
|
||
Diluted loss per share
|
|
$
|
(0.56
|
)
|
|
$
|
(0.50
|
)
|
(a)
|
No
incremental shares of potentially dilutive restricted stock awards were included for periods presented as their effect was antidilutive under the treasury stock method.
|
12.
|
Equity Based Compensation
|
13.
|
Stock-Based Compensation
|
|
|
Number of Unvested Restricted Stock Units
|
|
Weighted Average Grant-Date Fair Value
|
|||
Unvested restricted stock units as of October 19, 2016
|
|
—
|
|
|
$
|
—
|
|
Granted
|
|
298,335
|
|
|
$
|
14.97
|
|
Vested
|
|
(11,110
|
)
|
|
$
|
(14.69
|
)
|
Forfeited
|
|
(4,445
|
)
|
|
$
|
(15.00
|
)
|
Unvested restricted stock units as of December 31, 2016
|
|
282,780
|
|
|
$
|
14.98
|
|
Granted
|
|
460,185
|
|
|
$
|
20.72
|
|
Vested
|
|
(97,890
|
)
|
|
$
|
(15.07
|
)
|
Forfeited
|
|
(4,443
|
)
|
|
$
|
(15.00
|
)
|
Unvested restricted stock units as of December 31, 2017
|
|
640,632
|
|
|
$
|
19.44
|
|
14.
|
Acquisitions
|
Consideration attributable to Cementing
(1)
|
|
$
|
12,975
|
|
Consideration attributable to SR Energy
(1)
|
|
12,787
|
|
|
Total consideration transferred
|
|
$
|
25,762
|
|
|
|
SR Energy
|
Cementing
|
|
Total
|
||||||
|
|
(in thousands)
|
|||||||||
Cash and cash equivalents
|
|
$
|
1,611
|
|
$
|
1,060
|
|
|
$
|
2,671
|
|
Accounts receivable, net
|
|
3,913
|
|
495
|
|
|
4,408
|
|
|||
Receivables from related parties
|
|
3,684
|
|
1,418
|
|
|
5,102
|
|
|||
Inventories
|
|
—
|
|
306
|
|
|
306
|
|
|||
Prepaid expenses
|
|
35
|
|
32
|
|
|
67
|
|
|||
Property, plant and equipment
(1)
|
|
13,061
|
|
7,459
|
|
|
20,520
|
|
|||
Identifiable intangible assets - customer relationships
(2)
|
|
—
|
|
1,140
|
|
|
1,140
|
|
|||
Identifiable intangible assets - trade names
(2)
|
|
550
|
|
270
|
|
|
820
|
|
|||
Goodwill
(3)
|
|
3,929
|
|
6,264
|
|
|
10,193
|
|
|||
Other assets
|
|
7
|
|
—
|
|
|
7
|
|
|||
Total assets acquired
|
|
$
|
26,790
|
|
$
|
18,444
|
|
|
$
|
45,234
|
|
|
|
|
|
|
|
||||||
Accounts payable and accrued liabilities
|
|
$
|
5,890
|
|
$
|
2,063
|
|
|
$
|
7,953
|
|
Long-term debt
(4)
|
|
5,074
|
|
2,000
|
|
|
7,074
|
|
|||
Deferred tax liability
|
|
3,039
|
|
1,406
|
|
|
4,445
|
|
|||
Total liabilities assumed
|
|
$
|
14,003
|
|
$
|
5,469
|
|
|
$
|
19,472
|
|
Net assets acquired
|
|
$
|
12,787
|
|
$
|
12,975
|
|
|
$
|
25,762
|
|
(1)
|
Property, plant and equipment fair value measurements were prepared by utilizing a combined fair market value and cost approach. The market approach relies on comparability of assets using market data information. The cost approach places emphasis on the physical components and characteristics of the asset. It places reliance on estimated replacement cost, depreciation and economic obsolescence.
|
(2)
|
Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "relief-from-Royalty" method. Non-contractual customer relationships were valued using a "multi-period excess earnings" method. Identifiable intangible assets will be amortized over
5
-
10
years.
|
(3)
|
Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability based on the synergies expected to arise from the acquired entities.
|
(4)
|
Long-term debt assumed was paid off subsequent to the acquisition.
|
|
|
Year Ended December 31,
|
|||||
|
|
2017
|
2016
|
||||
Revenues
(a)
|
|
$
|
35,142
|
|
$
|
23,659
|
|
Net loss
|
|
(4,066
|
)
|
(8,171
|
)
|
|
|
Total
|
||
Property, plant and equipment
(1)
|
|
$
|
23,373
|
|
Sand reserves
(2)
|
|
20,910
|
|
|
Total assets acquired
|
|
$
|
44,283
|
|
|
|
|
||
Asset retirement obligation
|
|
1,732
|
|
|
Total liabilities assumed
|
|
$
|
1,732
|
|
Total allocation of purchase price
|
|
$
|
42,551
|
|
Bargain purchase price
(3, 4)
|
|
(6,231
|
)
|
|
Total purchase price
|
|
$
|
36,320
|
|
(1)
|
Property, plant and equipment fair value measurements were prepared by utilizing a combined fair market value and cost approach. The market approach relies on comparability of assets using market data information. The cost approach places emphasis on the physical components and characteristics of the asset. It places reliance on estimated replacement cost, depreciation and economic obsolescence.
|
(2)
|
The fair value of the sand reserves was determined based on the excess cash flow method, a form of the income approach. The method provides a value based on the estimated remaining life of sand reserves, projected financial information and industry projections.
|
(3)
|
Amount in Consolidated Statements of Comprehensive Income (Loss) reflected net of income taxes of
$2.2 million
.
|
(4)
|
The fair value of the business was determined based on the excess cash flow method, a form of the income approach.
|
|
|
2017
|
||
|
|
Piranha
|
||
Revenues
(a)
|
|
$
|
22,847
|
|
Net income
(b)
|
|
5,520
|
|
|
|
Year Ended December 31,
|
|||||
|
|
2017
|
2016
|
||||
Revenues
(a)
|
|
$
|
22,847
|
|
$
|
7,690
|
|
Net income
|
|
5,655
|
|
34,127
|
|
|
|
Higher Power
|
||
Property, plant and equipment
|
|
$
|
1,744
|
|
Identifiable intangible assets - customer relationships
|
|
1,613
|
|
|
Goodwill
(1)
|
|
643
|
|
|
Total assets acquired
|
|
$
|
4,000
|
|
(1)
|
Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability expected to arise from the acquired entity.
|
|
|
2017
|
||
|
|
Higher Power
|
||
Revenues
(a)
|
|
$
|
39,571
|
|
Net income
(b)
|
|
5,127
|
|
|
|
Year Ended December 31,
|
|||||
|
|
2017
|
2016
|
||||
Revenues
(a)
|
|
$
|
42,343
|
|
$
|
10,039
|
|
Net income (loss)
|
|
5,004
|
|
(1,189
|
)
|
|
|
5 Star
|
||
Accounts receivable
|
|
$
|
2,440
|
|
Property, plant and equipment
|
|
1,863
|
|
|
Identifiable intangible assets - trade names
(1)
|
|
300
|
|
|
Goodwill
(2)
|
|
248
|
|
|
Total assets acquired
|
|
$
|
4,851
|
|
|
|
|
||
Long-term debt and other liabilities
|
|
$
|
2,413
|
|
Total liabilities assumed
|
|
$
|
2,413
|
|
Net assets acquired
|
|
$
|
2,438
|
|
(1)
|
Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Non-contractual customer relationships were valued using a "Multi-period excess earnings" method. Identifiable intangible assets will be amortized over
5
-
10
years.
|
(2)
|
Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability expected to arise from the acquired entity.
|
|
|
2017
|
||
|
|
5 Star
|
||
Revenues
(a)
|
|
$
|
25,216
|
|
Net income
(b)
|
|
4,191
|
|
|
|
Year Ended December 31,
|
|||||
|
|
2017
|
2016
|
||||
Revenues
(a)
|
|
$
|
31,548
|
|
$
|
13,971
|
|
Net income (loss)
|
|
3,910
|
|
(839
|
)
|
15.
|
Related Party Transactions
|
|
|
REVENUES
|
|
ACCOUNTS RECEIVABLE
|
|||||||||||||
|
|
Years Ended December 31,
|
|
At December 31,
|
|||||||||||||
|
|
2017
|
2016
|
2015
|
|
2017
|
2016
|
||||||||||
Pressure Pumping and Gulfport
|
(a)
|
$
|
144,473
|
|
$
|
102,390
|
|
$
|
124,311
|
|
|
$
|
25,054
|
|
$
|
19,095
|
|
Muskie and Gulfport
|
(b)
|
42,956
|
|
25,783
|
|
38,182
|
|
|
1,947
|
|
5,373
|
|
|||||
Panther and Gulfport
|
(c)
|
3,253
|
|
3,011
|
|
3,703
|
|
|
872
|
|
1,434
|
|
|||||
Redback Energy and Gulfport
|
(d)
|
—
|
|
—
|
|
2,549
|
|
|
—
|
|
—
|
|
|||||
Cementing and Gulfport
|
(e)
|
7,410
|
|
—
|
|
—
|
|
|
2,255
|
|
—
|
|
|||||
SR Energy and Gulfport
|
(f)
|
10,129
|
|
—
|
|
—
|
|
|
3,348
|
|
—
|
|
|||||
Bison Drilling and El Toro
|
(g)
|
—
|
|
372
|
|
521
|
|
|
—
|
|
—
|
|
|||||
Panther and El Toro
|
(g)
|
96
|
|
172
|
|
192
|
|
|
—
|
|
—
|
|
|||||
Bison Trucking and El Toro
|
(g)
|
—
|
|
130
|
|
145
|
|
|
—
|
|
—
|
|
|||||
Redback Energy and El Toro
|
(h)
|
216
|
|
530
|
|
168
|
|
|
—
|
|
108
|
|
|||||
Coil Tubing and El Toro
|
(i)
|
161
|
|
319
|
|
—
|
|
|
—
|
|
—
|
|
|||||
Bison Drilling and Predator
|
(j)
|
234
|
|
—
|
|
—
|
|
|
234
|
|
—
|
|
|||||
The Company and 2017 Stingray Companies
|
(k)
|
63
|
|
38
|
|
9
|
|
|
—
|
|
1,363
|
|
|||||
Other Relationships
|
|
29
|
|
185
|
|
955
|
|
|
78
|
|
216
|
|
|||||
|
|
$
|
209,020
|
|
$
|
132,930
|
|
$
|
170,735
|
|
|
$
|
33,788
|
|
$
|
27,589
|
|
a.
|
Pressure Pumping provides pressure pumping, stimulation and related completion services to Gulfport.
|
b.
|
Muskie has agreed to sell and deliver, and Gulfport has agreed to purchase, specified annual and monthly amounts of natural sand proppant, subject to certain exceptions specified in the agreement, and pay certain costs and expenses.
|
c.
|
Panther performs drilling services for Gulfport pursuant to a master service agreement.
|
d.
|
Redback Energy performs completion and production services for Gulfport pursuant to a master service agreement.
|
e.
|
Cementing performs well cementing services for Gulfport.
|
f.
|
SR Energy performs well cementing services for Gulfport.
|
g.
|
The contract land and directional drilling segment provides services for El Toro, an affiliate of Wexford, pursuant to a master service agreement.
|
h.
|
Redback Energy performs completion and production services for El Toro pursuant to a master service agreement.
|
i.
|
Coil Tubing provides El Toro services in connection with completion activities.
|
j.
|
Bison Drilling provides equipment rentals to Predator, an entity in which Wexford owns a minority interest.
|
k.
|
The Company provided certain services to the 2017 Stingray Companies.
|
|
|
COST OF REVENUE
|
|
ACCOUNTS PAYABLE
|
|||||||||||||
|
|
Years Ended December 31,
|
|
At December 31,
|
|||||||||||||
|
|
2017
|
2016
|
2015
|
|
2017
|
2016
|
||||||||||
Cobra and T&E
|
(a)
|
610
|
|
—
|
|
—
|
|
|
457
|
|
—
|
|
|||||
Higher Power and T&E
|
(a)
|
25
|
|
—
|
|
—
|
|
|
3
|
|
—
|
|
|||||
Panther and DBDHT
|
(b)
|
196
|
|
49
|
|
101
|
|
|
77
|
|
—
|
|
|||||
Redback Energy and Elk City Yard
|
(c)
|
71
|
|
107
|
|
107
|
|
|
—
|
|
—
|
|
|||||
The Company and 2017 Stingray Companies
|
(d)
|
432
|
|
724
|
|
933
|
|
|
—
|
|
174
|
|
|||||
Other Relationships
|
|
74
|
|
186
|
|
238
|
|
|
218
|
|
3
|
|
|||||
|
|
$
|
1,408
|
|
$
|
1,066
|
|
$
|
1,379
|
|
|
$
|
755
|
|
$
|
177
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
SELLING, GENERAL AND ADMINISTRATIVE COSTS
|
|
|
|
||||||||||||
Consolidated and Everest
|
(e)
|
$
|
175
|
|
$
|
262
|
|
$
|
493
|
|
|
$
|
19
|
|
$
|
13
|
|
Consolidated and Wexford
|
(f)
|
892
|
|
394
|
|
384
|
|
|
150
|
|
13
|
|
|||||
Mammoth and Orange Leaf
|
(g)
|
46
|
|
102
|
|
50
|
|
|
—
|
|
—
|
|
|||||
Mammoth and Caliber
|
(h)
|
335
|
|
—
|
|
24
|
|
|
1
|
|
—
|
|
|||||
Other Relationships
|
|
33
|
|
—
|
|
—
|
|
|
2
|
|
—
|
|
|||||
|
|
$
|
1,481
|
|
$
|
758
|
|
$
|
951
|
|
|
$
|
172
|
|
$
|
26
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
CAPITAL EXPENDITURES
|
|
|
|
||||||||||||
Cobra and T&E
|
(a)
|
629
|
|
—
|
|
—
|
|
|
66
|
|
—
|
|
|||||
Higher Power and T&E
|
(a)
|
1,380
|
|
—
|
|
—
|
|
|
385
|
|
—
|
|
|||||
|
|
$
|
2,009
|
|
$
|
—
|
|
$
|
—
|
|
|
$
|
451
|
|
$
|
—
|
|
|
|
|
|
|
|
$
|
1,378
|
|
$
|
203
|
|
a.
|
Cobra and Higher Power purchase materials and services from T&E, an entity in which a member of management's family owns a minority interest.
|
b.
|
Panther rents rotary steerable equipment in connection with its directional drilling services from DBDHT, an affiliate of Wexford.
|
c.
|
Redback Energy leases property from Elk City Yard, an affiliate of Wexford.
|
d.
|
Prior to the 2017 Stingray Acquisition, the 2017 Stingray Companies provided certain services to the Company and, from time to time, the 2017 Stingray Companies paid for goods and services on behalf of the Company.
|
e.
|
Everest, a subsidiary of Wexford, has historically provided office space and certain technical, administrative and payroll services to the Company and the Company has reimbursed Everest in amounts determined by Everest based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for the Company.
|
f.
|
Wexford provides certain administrative and analytical services to the Company and, from time to time, the Company pays for goods and services on behalf of Wexford.
|
g.
|
Mammoth subleased office space from Orange Leaf, an entity in which a member of management and a member of management's family own, in the aggregate, a minority interest. The sublease was terminated in May 2017.
|
h.
|
Mammoth leases office space from Caliber, an entity controlled by Wexford.
|
16.
|
Commitments and Contingencies
|
Year ended December 31:
|
Operating Leases
|
|
Capital Spend Commitments
|
|
Minimum Purchase Commitments
|
||||||
2018
|
$
|
20,407
|
|
|
$
|
19,582
|
|
|
$
|
32,222
|
|
2019
|
14,200
|
|
|
—
|
|
|
10,866
|
|
|||
2020
|
11,864
|
|
|
—
|
|
|
—
|
|
|||
2021
|
9,303
|
|
|
—
|
|
|
—
|
|
|||
2022
|
6,515
|
|
|
—
|
|
|
—
|
|
|||
Thereafter
|
3,345
|
|
|
—
|
|
|
—
|
|
|||
|
$
|
65,634
|
|
|
$
|
19,582
|
|
|
$
|
43,088
|
|
|
|
December 31,
|
||||||
|
|
2017
|
|
2016
|
||||
Environmental remediation
|
|
$
|
3,582
|
|
|
$
|
1,375
|
|
Insurance programs
|
|
2,486
|
|
|
1,636
|
|
||
Rail car commitments
|
|
455
|
|
|
455
|
|
||
Total letters of credit
|
|
$
|
6,523
|
|
|
$
|
3,466
|
|
17.
|
Reporting Segments and Geographic Areas
|
Year Ended December 31, 2017
|
Pressure Pumping
|
Infrastructure
|
Sand
|
Drilling
|
All Other
(a)
|
Eliminations
|
Total
|
||||||||||||||
Revenue from external customers
|
$
|
277,326
|
|
$
|
224,425
|
|
$
|
90,023
|
|
$
|
50,075
|
|
$
|
49,647
|
|
$
|
—
|
|
$
|
691,496
|
|
Intersegment revenues
|
2,026
|
|
—
|
|
27,014
|
|
446
|
|
2,081
|
|
(31,567
|
)
|
—
|
|
|||||||
Total revenue
|
279,352
|
|
224,425
|
|
117,037
|
|
50,521
|
|
51,728
|
|
(31,567
|
)
|
691,496
|
|
|||||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
183,089
|
|
120,117
|
|
91,049
|
|
46,701
|
|
41,613
|
|
—
|
|
482,569
|
|
|||||||
Intersegment cost of revenues
|
28,147
|
|
1,443
|
|
1,731
|
|
146
|
|
65
|
|
(31,532
|
)
|
—
|
|
|||||||
Total cost of revenue
|
211,236
|
|
121,560
|
|
92,780
|
|
46,847
|
|
41,678
|
|
(31,532
|
)
|
482,569
|
|
|||||||
Selling, general and administrative
|
9,501
|
|
21,606
|
|
8,190
|
|
5,510
|
|
5,079
|
|
—
|
|
49,886
|
|
|||||||
Depreciation, depletion, amortization and accretion
|
45,413
|
|
3,185
|
|
9,394
|
|
19,635
|
|
14,497
|
|
—
|
|
92,124
|
|
|||||||
Impairment of long-lived assets
|
—
|
|
—
|
|
324
|
|
3,822
|
|
—
|
|
—
|
|
4,146
|
|
|||||||
Operating income (loss)
|
13,202
|
|
78,074
|
|
6,349
|
|
(25,293
|
)
|
(9,526
|
)
|
(35
|
)
|
62,771
|
|
|||||||
Interest expense
|
1,622
|
|
241
|
|
679
|
|
1,695
|
|
73
|
|
—
|
|
4,310
|
|
|||||||
Bargain purchase gain
|
—
|
|
—
|
|
(4,012
|
)
|
—
|
|
—
|
|
—
|
|
(4,012
|
)
|
|||||||
Other expense
|
129
|
|
6
|
|
211
|
|
256
|
|
75
|
|
—
|
|
677
|
|
|||||||
Income (loss) before income taxes
|
$
|
11,451
|
|
$
|
77,827
|
|
$
|
9,471
|
|
$
|
(27,244
|
)
|
$
|
(9,674
|
)
|
$
|
(35
|
)
|
$
|
61,796
|
|
Total expenditures for property, plant and equipment
|
$
|
85,853
|
|
$
|
20,144
|
|
$
|
16,376
|
|
$
|
8,927
|
|
$
|
2,553
|
|
$
|
—
|
|
$
|
133,853
|
|
As of December 31, 2017:
|
|
|
|
|
|
|
|
||||||||||||||
Goodwill
|
$
|
86,043
|
|
$
|
891
|
|
$
|
2,684
|
|
$
|
—
|
|
$
|
10,193
|
|
$
|
—
|
|
$
|
99,811
|
|
Intangible assets, net
|
$
|
12,392
|
|
$
|
1,770
|
|
$
|
—
|
|
$
|
—
|
|
$
|
1,977
|
|
$
|
—
|
|
$
|
16,139
|
|
Total assets
|
$
|
297,140
|
|
$
|
205,275
|
|
$
|
190,859
|
|
$
|
88,527
|
|
$
|
243,767
|
|
$
|
(158,325
|
)
|
$
|
867,243
|
|
a.
|
Includes results for operations previously included in the well services and other energy services segments.
|
Year Ended December 31, 2016
|
Pressure Pumping
|
Well Services
|
Sand
|
Drilling
|
Other Energy Services
|
Eliminations
|
Total
|
||||||||||||||
Revenue from external customers
|
$
|
123,856
|
|
$
|
10,024
|
|
$
|
33,835
|
|
$
|
32,043
|
|
$
|
30,867
|
|
$
|
—
|
|
$
|
230,625
|
|
Intersegment revenues
|
569
|
|
79
|
|
4,267
|
|
—
|
|
—
|
|
(4,915
|
)
|
—
|
|
|||||||
Total revenue
|
124,425
|
|
10,103
|
|
38,102
|
|
32,043
|
|
30,867
|
|
(4,915
|
)
|
230,625
|
|
|||||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
82,552
|
|
13,540
|
|
31,895
|
|
31,848
|
|
13,186
|
|
—
|
|
173,021
|
|
|||||||
Intersegment cost of revenues
|
4,336
|
|
26
|
|
561
|
|
(8
|
)
|
—
|
|
(4,915
|
)
|
—
|
|
|||||||
Total cost of revenue
|
86,888
|
|
13,566
|
|
32,456
|
|
31,840
|
|
13,186
|
|
(4,915
|
)
|
173,021
|
|
|||||||
Selling, general and administrative
|
4,327
|
|
2,336
|
|
3,337
|
|
5,625
|
|
2,423
|
|
—
|
|
18,048
|
|
|||||||
Depreciation, depletion, amortization and accretion
|
37,013
|
|
5,128
|
|
6,483
|
|
21,512
|
|
2,179
|
|
—
|
|
72,315
|
|
|||||||
Impairment of long-lived assets
|
139
|
|
1,385
|
|
—
|
|
347
|
|
—
|
|
—
|
|
1,871
|
|
|||||||
Operating loss
|
(3,942
|
)
|
(12,312
|
)
|
(4,174
|
)
|
(27,281
|
)
|
13,079
|
|
—
|
|
(34,630
|
)
|
|||||||
Interest expense
|
599
|
|
134
|
|
434
|
|
2,829
|
|
100
|
|
—
|
|
4,096
|
|
|||||||
Other expense (income)
|
27
|
|
(566
|
)
|
96
|
|
248
|
|
37
|
|
—
|
|
(158
|
)
|
|||||||
(Loss) income before income taxes
|
$
|
(4,568
|
)
|
$
|
(11,880
|
)
|
$
|
(4,704
|
)
|
$
|
(30,358
|
)
|
$
|
12,942
|
|
$
|
—
|
|
$
|
(38,568
|
)
|
Total expenditures for property, plant and equipment
|
7,673
|
|
405
|
|
528
|
|
2,709
|
|
425
|
|
—
|
|
11,740
|
|
|||||||
As of December 31, 2016:
|
|
|
|
|
|
|
|
||||||||||||||
Goodwill
|
$
|
86,043
|
|
$
|
—
|
|
$
|
2,684
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
88,727
|
|
Intangible assets, net
|
$
|
21,435
|
|
$
|
132
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
21,567
|
|
Total assets
|
$
|
197,635
|
|
$
|
128,698
|
|
$
|
109,128
|
|
$
|
99,868
|
|
$
|
48,653
|
|
$
|
(81,620
|
)
|
$
|
502,362
|
|
Year Ended December 31, 2015
|
Pressure Pumping
|
Well Services
|
Sand
|
Drilling
|
Other Energy Services
|
Eliminations
|
Total
|
||||||||||||||
Revenue from external customers
|
$
|
169,859
|
|
$
|
28,851
|
|
$
|
60,913
|
|
$
|
73,032
|
|
$
|
35,282
|
|
$
|
—
|
|
$
|
367,937
|
|
Intersegment revenue
|
759
|
|
—
|
|
5,144
|
|
1
|
|
—
|
|
(5,904
|
)
|
—
|
|
|||||||
Total revenue
|
170,618
|
|
28,851
|
|
66,057
|
|
73,033
|
|
35,282
|
|
(5,904
|
)
|
367,937
|
|
|||||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
126,886
|
|
28,144
|
|
47,041
|
|
57,453
|
|
15,163
|
|
—
|
|
274,687
|
|
|||||||
Intersegment cost of revenues
|
5,243
|
|
205
|
|
456
|
|
—
|
|
—
|
|
(5,904
|
)
|
—
|
|
|||||||
Total cost of revenue
|
132,129
|
|
28,349
|
|
47,497
|
|
57,453
|
|
15,163
|
|
(5,904
|
)
|
274,687
|
|
|||||||
Selling, general and administrative
|
4,901
|
|
2,286
|
|
4,264
|
|
8,573
|
|
2,376
|
|
—
|
|
22,400
|
|
|||||||
Depreciation and amortization
|
35,729
|
|
5,697
|
|
6,305
|
|
24,627
|
|
2,141
|
|
—
|
|
74,499
|
|
|||||||
Impairment of long-lived assets
|
1,214
|
|
88
|
|
1,905
|
|
8,917
|
|
—
|
|
—
|
|
12,124
|
|
|||||||
Operating (loss) income
|
(3,355
|
)
|
(7,569
|
)
|
6,086
|
|
(26,537
|
)
|
15,602
|
|
—
|
|
(15,773
|
)
|
|||||||
Interest income
|
—
|
|
—
|
|
(98
|
)
|
—
|
|
—
|
|
—
|
|
(98
|
)
|
|||||||
Interest expense
|
1,822
|
|
429
|
|
225
|
|
2,928
|
|
61
|
|
—
|
|
5,465
|
|
|||||||
Other expense (income)
|
67
|
|
687
|
|
22
|
|
1,121
|
|
372
|
|
—
|
|
2,269
|
|
|||||||
Loss (income) before income taxes
|
$
|
(5,244
|
)
|
$
|
(8,685
|
)
|
$
|
5,937
|
|
$
|
(30,586
|
)
|
$
|
15,169
|
|
$
|
—
|
|
$
|
(23,409
|
)
|
Total expenditures for property, plant and equipment
|
$
|
4,170
|
|
$
|
6,768
|
|
$
|
2,371
|
|
$
|
12,651
|
|
$
|
2,492
|
|
$
|
—
|
|
$
|
28,452
|
|
As of December 31, 2015:
|
|
|
|
|
|
|
|
||||||||||||||
Goodwill
|
$
|
86,043
|
|
$
|
—
|
|
$
|
2,684
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
88,727
|
|
Intangible assets, net
|
$
|
30,479
|
|
$
|
159
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
$
|
30,638
|
|
Total assets
|
$
|
230,806
|
|
$
|
147,268
|
|
$
|
127,786
|
|
$
|
123,656
|
|
$
|
38,864
|
|
$
|
(131,968
|
)
|
$
|
536,412
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
United States
|
|
$
|
471,745
|
|
|
$
|
196,573
|
|
|
$
|
331,633
|
|
Puerto Rico
|
|
203,087
|
|
|
—
|
|
|
—
|
|
|||
Canada
|
|
16,664
|
|
|
34,052
|
|
|
36,304
|
|
|||
Total
|
|
$
|
691,496
|
|
|
$
|
230,625
|
|
|
$
|
367,937
|
|
|
Three Months Ended
|
|
|||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
Total
|
||||||||||
|
2017
|
2017
|
2017
|
2017
|
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Revenue from external customers
|
$
|
30,464
|
|
$
|
40,054
|
|
$
|
78,389
|
|
$
|
333,569
|
|
$
|
482,476
|
|
Revenue from related parties
|
44,502
|
|
58,208
|
|
70,916
|
|
35,394
|
|
209,020
|
|
|||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
58,498
|
|
77,340
|
|
114,533
|
|
232,198
|
|
482,569
|
|
|||||
Selling, general and administrative expenses
|
6,737
|
|
7,700
|
|
8,023
|
|
27,426
|
|
49,886
|
|
|||||
Depreciation, depletion, amortization and accretion
|
17,237
|
|
19,893
|
|
27,224
|
|
27,770
|
|
92,124
|
|
|||||
Impairment of long-lived assets
|
—
|
|
—
|
|
—
|
|
4,146
|
|
4,146
|
|
|||||
Operating income (loss)
|
(7,506
|
)
|
(6,671
|
)
|
(475
|
)
|
77,423
|
|
62,771
|
|
|||||
Interest expense
|
397
|
|
1,112
|
|
1,420
|
|
1,381
|
|
4,310
|
|
|||||
Bargain purchase gain
|
—
|
|
(4,012
|
)
|
—
|
|
—
|
|
(4,012
|
)
|
|||||
Other expense (income)
|
184
|
|
202
|
|
319
|
|
(28
|
)
|
677
|
|
|||||
(Loss) income before income taxes
|
(8,087
|
)
|
(3,973
|
)
|
(2,214
|
)
|
76,070
|
|
61,796
|
|
|||||
(Benefit) provision for income taxes
|
(3,106
|
)
|
(2,804
|
)
|
(1,413
|
)
|
10,155
|
|
2,832
|
|
|||||
Net (loss) income
|
$
|
(4,981
|
)
|
$
|
(1,169
|
)
|
$
|
(801
|
)
|
$
|
65,915
|
|
$
|
58,964
|
|
|
|
|
|
|
|
||||||||||
Net (loss) income per share (basic) (Note 11)
|
$
|
(0.13
|
)
|
$
|
(0.03
|
)
|
$
|
(0.02
|
)
|
$
|
1.48
|
|
$
|
1.42
|
|
Net (loss) income per share (diluted) (Note 11)
|
$
|
(0.13
|
)
|
$
|
(0.03
|
)
|
$
|
(0.02
|
)
|
$
|
1.48
|
|
$
|
1.42
|
|
Weighted average number of shares outstanding (Note 11)
|
37,500
|
|
39,500
|
|
44,502
|
|
44,579
|
|
41,548
|
|
|||||
Weighted average number of shares outstanding, including dilutive effect (Note 11)
|
37,500
|
|
39,500
|
|
44,502
|
|
44,683
|
|
41,639
|
|
|
Three Months Ended
|
|
|||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
Total
|
||||||||||
|
2016
|
2016
|
2016
|
2016
|
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Revenue from external customers
|
$
|
29,518
|
|
$
|
20,345
|
|
$
|
20,753
|
|
$
|
27,079
|
|
$
|
97,695
|
|
Revenue from related parties
|
3,065
|
|
48,817
|
|
42,574
|
|
38,474
|
|
132,930
|
|
|||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
32,391
|
|
50,504
|
|
42,855
|
|
47,271
|
|
173,021
|
|
|||||
Selling, general and administrative expenses
|
3,614
|
|
5,206
|
|
3,195
|
|
6,033
|
|
18,048
|
|
|||||
Depreciation, depletion, amortization and accretion
|
17,751
|
|
18,811
|
|
17,921
|
|
17,832
|
|
72,315
|
|
|||||
Impairment of long-lived assets
|
—
|
|
1,871
|
|
—
|
|
—
|
|
1,871
|
|
|||||
Operating income (loss)
|
(21,173
|
)
|
(7,230
|
)
|
(644
|
)
|
(5,583
|
)
|
(34,630
|
)
|
|||||
Interest expense
|
1,296
|
|
1,012
|
|
1,025
|
|
763
|
|
4,096
|
|
|||||
Other expense (income)
|
1
|
|
(627
|
)
|
254
|
|
214
|
|
(158
|
)
|
|||||
Loss before income taxes
|
(22,470
|
)
|
(7,615
|
)
|
(1,923
|
)
|
(6,560
|
)
|
(38,568
|
)
|
|||||
Provision for income taxes
|
894
|
|
789
|
|
1,056
|
|
51,146
|
|
53,885
|
|
|||||
Net loss
|
$
|
(23,364
|
)
|
$
|
(8,404
|
)
|
$
|
(2,979
|
)
|
$
|
(57,706
|
)
|
$
|
(92,453
|
)
|
|
|
|
|
|
|
||||||||||
Net loss per share (basic and diluted) (Note 11)
|
$
|
(0.78
|
)
|
$
|
(0.28
|
)
|
$
|
(0.10
|
)
|
$
|
(1.61
|
)
|
$
|
(2.94
|
)
|
Weighted average number of shares outstanding (Note 11)
|
30,000
|
|
30,000
|
|
30,000
|
|
35,951
|
|
31,500
|
|
19.
|
Subsequent Events
|
Composite Labor & Equipment Rate
|
Rate: Day Rate
|
Description
|
Material Coordination
|
$1,000.00
|
The Composite rate is all inclusive of Overhead labor classifications, this rate is comprised of all labor, cost, and equipment, including all customary tooling, if any, required to perform the work.
|
Equipment
|
Lease Payment
|
Equipment Group A
|
$800.00 per day of use.
|
Equipment Group B
|
$450.00 per day of use.
|
1)
|
Maxum 1000 triplex mud pump/398 cat engine, with liner washer
|
2)
|
90 Jts of 4 1/2" 16.60# G105 drill pipe with 4 1/2" X-hole connections
|
3)
|
8 each - 6" drill collars with 4 1/2" X-hole connections
|
4)
|
3 each - 8" drill collars with 6/5/8" regular connections
|
5)
|
1 each 4 1/2" X-hole X 6 5/8" regular pin crossover subs
|
6)
|
1 each 4 1/2" X-hole circulating sub
|
7)
|
2 lift subs for 6" drill collars
|
8)
|
2 lift subs for 8" drill collars
|
9)
|
1 set 42" drillpipe racks
|
Equipment Group A
|
Maxum 1000 triplex mud pump/398 cat engine, with liner washer
|
Equipment Group B
|
90 Jts of 4 1/2" 16.60# G105 drill pipe with 4 1/2" X-hole connections
8 each - 6" drill collars with 4 1/2" X-hole connections
3 each - 8" drill collars with 6/5/8" regular connections
1 each 4 1/2" X-hole X 6 5/8" regular pin crossover subs
1 each 4 1/2" X-hole circulating sub
2 lift subs for 6" drill collars
2 lift subs for 8" drill collars
1 set 42" drill pipe racks
|
Stated Value
|
Equipment
|
$37,500
|
Maxum 1000 triplex mud pump/398 cat engine, with liner washer
|
$10,800
|
90Jts of 4 1/2" 16.60# G105 drill pipe with 4 1/2" X-hole connections
|
$3,200
|
8 each - 6" drillcollars with 4 1/2" X-hole connections
|
$2,400
|
3 each - 8" drillcollars with 6/5/8" regular connections
|
$100
|
1 each 4 1/2" X-hole X 6 5/8" regular pin crossover sub
|
$100
|
1 each 4 1/2" X-hole circulating sub
|
$200
|
2 lift subs for 6" drillcollars
|
$200
|
2 lift subs for 8" drillcollars
|
$1,000
|
1 set 42" drillpipe racks
|
$55,500
|
Total
|
Equipment
|
Lease Payment
|
Equipment Group A
|
$800.00 per day of use.
|
Equipment Group B
|
$450.00 per day of use.
|
1)
|
MZ9 triplex mud pump w/ Cat 398 engine (liner washer built in) (Eng Ser #35Z00702)
|
2)
|
90 JTS of 4 ½” 16.60# G105 drill pipe with 4 ½” X-hole connections
|
3)
|
8ea - 6” drill collars w/ 4 ½” X-hole connections & 2 lift subs
|
4)
|
3ea - 8” drill collars w/ 6 5/8” Regular connections & 2 lift subs
|
5)
|
1ea - 4 ½” X-hole box X 6 5/8” Regular pin crossover sub
|
6)
|
1ea - 4 ½”IF box X 4 ½” X-hole pin sub
|
7)
|
1ea - 4 ½” X-hole pin X 4 ½” X-hole box (burn sub)
|
8)
|
2 lift subs for 6" drill collars
|
9)
|
2 lift subs for 8" drill collars
|
10)
|
1 each 250 Ton 4 1/2 " bottleneck elevators - Serial No#-WOE102534-01 LT-08-16
|
Equipment Group A
|
MZ9 triplex mud pump w/ Cat 398 engine (liner washer built in) (Eng Ser #35Z00702)
|
Equipment Group B
|
90 JTS of 4 ½” 16.60# G105 drill pipe with 4 ½” X-hole connections
8ea - 6” drill collars w/ 4 ½” X-hole connections & 2 lift subs
3ea - 8” drill collars w/ 6 5/8” Regular connections & 2 lift subs
1ea - 4 ½” X-hole box X 6 5/8” Regular pin crossover sub
1ea - 4 ½”IF box X 4 ½” X-hole pin sub
1ea - 4 ½” X-hole pin X 4 ½” X-hole box (burn sub)
2 lift subs for 6" drill collars
2 lift subs for 8" drill collars
1 each 250 Ton 4 1/2 " bottleneck elevators - Serial No#-WOE102534-01 LT-08-16
|
Stated Value
|
Equipment
|
$37,500
|
MZ9 triplex mud pump/398 cat engine, with liner washer, engine ser# 35Z00702
|
$10,800
|
90 Jts of 4 1/2" 16.60# G105 drill piupe with 4 1/2" X-hole connections
|
$3,200
|
8 each - 6" drillcollars with 4 1/2" X-hole connections
|
$2,400
|
3 each - 8" drillcollars with 6/5/8" regular connections
|
$100
|
1 each 4 1/2" X-hole X 6 5/8" regular pin crossover sub
|
$100
|
1 each 4 1/2" IF Box X 4 1/2" X hole pin sub
|
$100
|
1 each 4 1/2" X-hile pin X 4 1/2" X hole box (burn sub)
|
$200
|
2 lift subs for 6" drillcollars
|
$200
|
2 lift subs for 8" drillcollars
|
$1,000
|
1 each 250 Ton 4 1/2 " bottleneck elevators - Serial No#-WOE102534-01 LT-08-16
|
$55,600
|
Total
|
1.
|
PREPA and the Contractor agree that Article 3 of the Original Contract is hereby amended by striking the dollar amount of “$445,429,800 (Contract Amount)” appearing on the seventh (7th) line of such article and replacing it with the following dollar amount: “$945,429,800 (Contract Amount)”.
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2.
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PREPA and the Contractor agree that the first paragraph of Article 14 of the Contract is hereby amended by striking the first paragraph thereof and replacing it with the following:
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“1)
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Notwithstanding anything to the contrary in this Contract regarding its term, PREPA may, at any moment, terminate, cancel or accelerate its expiration, after giving the Contractor not less than thirty (30) days prior written notice, for any or no reason, when in PREPA’s judgment such action responds to its best interest. PREPA may terminate this Agreement immediately at any time in cases of gross negligence by the Contractor upon written notice to Contractor specifying such gross negligence.”
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3.
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Materials. The Parties agree that the Contractor may purchase and provide PREPA with materials needed for the restoration work of the electrical system (the “Materials”), subject to the following terms and conditions:
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(a)
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Prior to placing the order for any Materials, the Contractor shall provide to PREPA a schedule of the costs of such Materials on a pass-through basis and the cost for transportation, for final review and approval by PREPA. No purchases shall be made by Contractor on behalf of PREPA except with prior written authorization from PREPA;
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(b)
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All Materials will comply with specifications provided by PREPA.
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(c)
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All Material procurements by Contractor must comply with Federal regulations under the Code of Federal Regulations Title 2 Sections 200.317 to 200.321, 200.326, 200.333 and Appendix II.
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(d)
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Contractor will complete all purchases in accordance with all Puerto Rico laws, rules and regulations, including but not limited to Act 83, Regulation 8518 issued by PREPA, known as the Bid Regulation (Reglamento de Subastas), the Procedure for Purchases by Request for Quotes or Offers Exempt from Formal Bid Process (the “Procedures for Exempt Purchases”), and Chapter 500 of PREPA’s Administrative Manual (Purchases), as applicable. As provided Act 83 and the Bid Regulation, a bid process will not be required when, due to an emergency situation, immediate delivery of certain materials is required. In such cases, purchases shall be made by Contractor in accordance with the provisions of the Procedures for Exempt Purchases. PREPA will provide written notice to the Contractor when Procedures for Exempt Purchases is authorized.
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(e)
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PREPA will reimburse the Contractor for (i) the actual cost of the Materials on a pass-through basis and (ii) transportation costs.
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(f)
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Any profit of Contractor on transportation of materials must not be calculated on a “cost plus a percentage of cost” basis.
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(g)
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The Contractor will deliver the Materials to PREPA’s General Warehouse in Palo Seco or any other location identified by PREPA in writing at the time the order for the Materials is placed. All risk of loss of the Materials
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(h)
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The Contractor shall use its reasonable efforts to obtain the lowest prices available, while considering manufacturers capacity and/or supplier ability to meet the demand of the work schedules which may require procurement from different manufacturers and suppliers.
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(i)
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For any Materials procured under Emergency Procedures, PREPA will certify that each material procurement was necessary due to emergency or exigent circumstances and complies with PREPA’s policies and regulations for emergency procurement.
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(j)
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It is the responsibility of the Contractor to maintain records sufficient to detail the history of procurement. These records will include, but are not necessarily limited to the following: (i) rationale for the method of procurement, (ii) rationale for the election of contract type, (iii) criteria for contractor selection or rejection, (iv) basis for the contract price, (v) documentation of reasonableness of the costs based on multiple quotations and/or pricing solicitations whenever possible to support the costs claimed, (vi) evidence provided by PREPA of emergency situations and immediate need for materials to support that such purchase is exempt from a formal bid process, as required under Act 83, (vii) other evidence of compliance with the applicable purchasing procedures and (viii) any other documentation required by federal or state law. Upon request by PREPA, Contractor shall deliver to PREPA a file containing all documentation described herein.
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(k)
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For any Materials to be procured by the Contractor, PREPA shall review the procurement and will provide certification regarding procurement compliance with Section 15(b) (2) of Act No. 83 of May 2, 1941, as amended, PREPA’s internal policies, and all required statutory and contractual provisions.
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4.
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The Contractor shall submit invoices for Materials separately from invoices for other work performed under the Contract. All invoices will be delivered in compliance with the provisions of Section 3 of the Contract, as amended.
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5.
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By signing below, the Contractor certifies that no other Federal, State or local agencies, non-insurance agency or any other entity has paid or will pay Contractor for Material costs paid to Contractor by PREPA.
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6.
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The Parties agree that the third paragraph of Article 3, Consideration, of the Original Contract is hereby stricken and replaced with the following four paragraphs:
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7.
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PREPA hereby acknowledges and accepts that the Contractor has delivered to PREPA the certifications required under Executive Orders OE-1991-24 and OE-1992-52 as well as a copy of Contractor’s Certificate of Formation.
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8.
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PREPA hereby certifies that no public officer or employee of PREPA who has the power to approve or authorize contracts has evaluated, considered, approved or authorized any contract between PREPA and Contractor in which he/she or any member of his/her family unit has or has had direct or indirect economic interest during the last four (4) years prior to his/her holding office.
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9.
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The definition of “Contract” contained in Article 2, paragraph 3) of the Original Contract is hereby amended by deleting therefrom the following text inadvertently appearing on lines two and three thereof: “, which constitute an amendment and supersedes to that contract entered into by the parties on September 26, 2017,”
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10.
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PREPA shall not approve the purchase of any Materials under this Amendment until this Amendment is properly registered in the Office of the Controller of the Government of Puerto Rico.
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12.
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Employees not to Benefit: The Parties hereby declare that, to the best of their knowledge, no public officer or employee of the Commonwealth of Puerto Rico, its agencies, instrumentalities, public corporations or municipalities or employee of the Legislative or Judicial branches of the Government has any direct or indirect interest in the present Agreement. The Contractor certifies that neither it nor any of its partners, directors, executives, officers, and employees receives salary or any kind of compensation for the delivery of regular services by appointment in any agency, instrumentality, public corporation, or municipality of the Commonwealth of Puerto Rico.
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13.
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PREPA hereby certifies that this Amendment has been approved by the delegate of the Governor of Puerto Rico, as required under Act 3-2017 and Office of the Chief of Staff Memorandum No. 2017-001; Office of Management and Budget Circular Letter 141-17.
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14.
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Except as set forth herein, the Contract remains in full force and effect in accordance with its terms.
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Name of Subsidiary
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5 Star Electric LLC
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Barracuda Logistics LLC
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Bison Drilling and Field Services LLC
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Bison Trucking LLC
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Cobra Acquisitions LLC
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Cobra Energy LLC
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Great White Sand Tiger Lodging Ltd.
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Higher Power Electrical LLC
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Mammoth Energy Partners LLC
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Mammoth Energy Services Inc.
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Mammoth Equipment Leasing LLC
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Mr. Inspections LLC
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Muskie Proppant LLC
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Panther Drilling Systems LLC
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Piranha Proppant LLC
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Redback Coil Tubing LLC
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Redback Energy Services LLC
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Redback Pumpdown Services LLC
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Silverback Energy Services LLC
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South River Road LLC
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Stingray Cementing LLC
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Stingray Energy Services LLC
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Stingray Logistics LLC
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Stingray Pressure Pumping LLC
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Sturgeon Acquisitions LLC
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Taylor Frac LLC
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Taylor Real Estate Investments LLC
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Tiger Shark Logistics LLC
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White Wing Tubular Services LLC
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1.
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I have reviewed this Annual Report on Form 10-K of Mammoth Energy Services, Inc. (the “registrant”);
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:
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a.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:
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b.
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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c.
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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d.
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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a.
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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b.
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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MAMMOTH ENERGY SERVICES, INC.
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By:
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/s/ Arty Straehla
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Arty Straehla
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Chief Executive Officer
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February 28, 2018
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|
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|
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1.
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I have reviewed this Annual Report on Form 10-K of Mammoth Energy Services, Inc. (the “registrant”);
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:
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a.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:
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b.
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
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c.
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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d.
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
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b.
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
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MAMMOTH ENERGY SERVICES, INC.
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By:
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/s/ Mark Layton
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Mark Layton
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Chief Financial Officer
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February 28, 2018
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|
|
|
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”); and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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MAMMOTH ENERGY SERVICES, INC.
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By:
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/s/ Arty Straehla
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Arty Straehla
|
|
|
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Chief Executive Officer
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February 28, 2018
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|
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|
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”); and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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MAMMOTH ENERGY SERVICES, INC.
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By:
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/s/ Mark Layton
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Mark Layton
|
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|
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Chief Financial Officer
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February 28, 2018
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•
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Section 104 S&S Citations: Citations received from MSHA under section 104 of the Mine Act for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard.
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•
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Section 104(b) Orders: Orders issued by MSHA under section 104(b) of the Mine Act, which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated.
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•
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Section 104(d) Citations and Orders: Citations and orders issued by MSHA under section 104(d) of the Mine Act for unwarrantable failure to comply with mandatory health or safety standards.
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•
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Section 110(b)(2) Violations: Flagrant violations issued by MSHA under section 110(b)(2) of the Mine Act.
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•
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Section 107(a) Orders: Orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an “imminent danger” (as defined by MSHA) existed.
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Mine (a)
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Section 104
S&S
Citations(#)
|
Section104(b)Orders (#)
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Section104(d)Citations and Orders(#)
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Section 110(b)(2) Violations(#)
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Section107(a)Orders (#)
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Proposed Assessments (2)($, amounts in dollars)
|
Mining Related Fatalities (#)
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||||||||
Taylor, WI
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2
|
|
—
|
|
—
|
|
—
|
|
—
|
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$
|
289
|
|
—
|
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Plum City, WI
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1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
$
|
116
|
|
—
|
|
New Auburn, WI
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
$
|
—
|
|
—
|
|
a.
|
The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools and minerals preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. MSHA assigns an identification number to each mine and may or may not assign separate identification numbers to related facilities such as preparation facilities. We are providing the information in the table by mine rather than MSHA identification number because that is how we manage and operate our mining business and we believe this presentation will be more useful to investors than providing information based on MSHA identification numbers.
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b.
|
Represents the total dollar value of proposed assessments from MSHA under the Mine Act relating to any type of citation or order issued during the year ended
December 31, 2017
.
|