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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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Acidizing
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To pump acid into a wellbore to improve a well's productivity or injectivity.
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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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Flowback
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The process of allowing fluids to flow from the well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production.
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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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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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our ability to execute our business strategy;
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any loss of one or more of our significant customers and its impact on our revenue, financial condition and results of operations;
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our ability to identify, complete and integrate acquisitions of assets or businesses;
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our ability to obtain permits and governmental approvals and to comply with applicable governmental laws and regulations;
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outcome of a government investigation relating to the contracts awarded to one of our subsidiaries by the Puerto Rico Electric Power Authority and any resulting litigation;
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outcome of pending litigation discussed in this report;
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any future litigation, indemnity or other claims;
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the availability of transportation facilities and any increase in transportation and related costs;
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access to and restrictions on use of water;
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technology;
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general economic, business or industry conditions;
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competition within the energy services industry;
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demand for oil and natural gas and infrastructure services and frac sand;
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volatility of the oil and natural gas industry and commodity prices;
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availability of equipment, materials or skilled labor;
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financial strategy;
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our ability to obtain capital or financing on satisfactory terms or at all;
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future operating results; and
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capital expenditures and other 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; and
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The oil sands in Alberta, Canada.
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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, 2019, 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, 2019, we had seven fluid pumping units. Five of these units 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. Two of these units are quintuplex pump units capable of output of up to 15 barrels per minute, and are rated for pressures up to 15,000 psi.
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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 12.2 million barrels per day during 2019, an increase of 11.4% from 2018, with December 2019 average production of approximately 12.9 million barrels per day. U.S. average petroleum field production has grown at a compound annual growth rate of 9.2% over the period from 2009 through 2019 due to production gains primarily from unconventional reservoirs. We expect continued growth from unconventional reservoirs in the future will result in increased demand for our services due to higher decline rates from these reservoirs, resulting in increased activity levels.
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Increased use of horizontal drilling to develop unconventional resource plays. According to Baker Hughes, the horizontal rig count on December 27, 2019 was 703, or approximately 87% of the total U.S. onshore rig count. 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 8.2 million barrels per day in 2019, representing approximately 63% of total U.S. crude oil production in 2019. 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
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Horizontal wells are heavily dependent on oilfield services. According to Baker Hughes, as of December 27, 2019, horizontal rigs accounted for approximately 87% 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, SCOOP/STACK, 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 and Powder River Basin 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 they typically require the use of extended reach horizontal drilling, multiple stage fracture stimulation and high pressure completion capabilities.
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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 to maintain and grow current production levels. 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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Long-term contractual and other regional relationships with a stable customer base. We are party to two long-term contracts with Gulfport to provide pressure pumping services and natural sand proppant services through December 2021, although Gulfport is seeking to terminate the pressure pumping contract. See Note 20. Commitments and Contingencies to our consolidated financial statements included elsewhere in this annual report. 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.
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Strategic geographic positioning, including primary presence in the Utica Shale, the SCOOP/STACK 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 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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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 27 years of infrastructure services experience and over 37 years of oilfield services experience. In addition, our field managers have expertise in the areas in which they operate and understand the challenges that our customers face. We believe their knowledge of our industries and
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Young 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. We believe that our fleet of quality equipment will allow us to provide a high level of service to our customers and capitalize on future growth in the unconventional resource plays that we serve. In addition, we are currently in the process of converting a portion of our pressure pumping fleet to include DGB capabilities to meet recent shifts in customer demand, with the initial converted units expected to be field tested in the coming weeks.
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Leverage our broad range of services for cross-selling opportunities. We offer a complementary suite of services and products. Our infrastructure services division provides construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our pressure pumping services division provide hydraulic fracturing services for unconventional wells as well as sand hauling services and water transfer services. Our natural sand proppant services division mines, processes and sells natural sand proppant for hydraulic fracturing. Our drilling services division provides rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling as well as rig moving services. Additionally, we provide coil tubing services, pressure control services, equipment rentals, crude oil hauling, full service transportation, remote accommodations, oilfield equipment manufacturing and infrastructure engineering services. We intend to leverage our existing customer relationships and operational track record to cross sell our services and increase our exposure and product offerings to our existing customers, broaden our customer base and expand opportunistically to other geographic regions in which our customers have operations, as well as to create operational efficiencies for our customers.
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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 infrastructure services, completion and production services and industrial based companies, 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 Capital LP, or Wexford, our 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.
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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 if, and when, 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. 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
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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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Capitalize on 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 2019, oil prices fluctuated between a low of $45.41 on January 1, 2019 and a high of $66.30 on April 23, 2019, and averaged $57.03 per barrel for the year. Certain factors related to world politics and major oil producers caused fluctuations in the oil price during 2019. However, overall, the price of oil was relatively stable throughout the year. If commodity prices stabilize at current levels or improve, we expect to experience increases in demand for our services and products. We will seek to capitalize on any 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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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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incurring additional indebtedness;
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paying dividends;
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creating certain additional liens on our assets;
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entering into sale and leaseback transactions;
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making investments;
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entering into transactions with affiliates;
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making material changes to the type of business we conduct or our business structure;
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making guarantees;
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entering into hedges;
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disposing of assets in excess of certain permitted amounts;
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merging or consolidating with other entities; and
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selling all or substantially all of our assets.
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the minimum interest coverage ratio of 3.0 to 1.0 was eliminated;
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the maximum leverage coverage ratio of 4.0 to 1.0 was eliminated for the first two fiscal quarters of 2020 and, beginning with the fiscal quarter ended September 30, 2020, changed to 2.5 to 1.0;
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beginning with the fiscal quarter ended September 30, 2020, a minimum fixed charge coverage ratio of at least 1.1 to 1.0 was added; and
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from the effective date of February 26, 2020 through September 30, 2020, a minimum excess availability covenant of 10% of the maximum revolving advance amount was added.
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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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global or national health concerns, including the outbreak of pandemic or contagious diseases such as the coronavirus;
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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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unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including but not limited to environmental liabilities;
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difficulties in integrating the operations and assets of the acquired business and the acquired personnel;
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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;
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potential losses of key employees and customers of the acquired businesses;
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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.
|
•
|
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
(Thousands of Tons)
|
|
Taylor in Jackson County, Wisconsin
|
|
2,646
|
|
Piranha in Barron County, Wisconsin
|
|
4,704
|
|
Muskie in Pierce County, Wisconsin
|
|
1,314
|
|
Dry Plant Location
|
|
Annual Rated Plant Capacity
(Thousands of Tons)(a)
|
|
Taylor in Jackson County, Wisconsin
|
|
2,190
|
|
Piranha in Barron County, Wisconsin
|
|
2,628
|
|
Muskie in Pierce County, Wisconsin
|
|
876
|
|
a.
|
Amounts represent rated production capacity. We estimate our annual company-wide functional production capacity is 4.4 million tons per year.
|
|
|
Estimated Proven Reserves (Thousands of Tons)
|
|||||||
Mine Location
|
|
December 31, 2019
|
|
December 31, 2018
|
|
December 31, 2017
|
|||
Taylor in Jackson County, Wisconsin
|
|
25,121
|
|
|
26,325
|
|
|
25,029
|
|
Piranha in Barron County, Wisconsin
|
|
41,001
|
|
|
42,358
|
|
|
38,150
|
|
Total
|
|
66,122
|
|
|
68,683
|
|
|
63,179
|
|
Item 5.
|
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
|
|
Per Share
|
|
Total
|
||||
|
|
|
(in thousands)
|
||||
2019
|
|
|
|
||||
Paid on February 14, 2019
|
$
|
0.125
|
|
|
$
|
5,609
|
|
Paid on May 17, 2019
|
0.125
|
|
|
5,610
|
|
||
Total cash dividends
|
$
|
0.25
|
|
|
$
|
11,219
|
|
2018
|
|
|
|
||||
Paid on August 14, 2018
|
$
|
0.125
|
|
|
$
|
5,595
|
|
Paid on November 15, 2018
|
0.125
|
|
|
5,606
|
|
||
Total cash dividends
|
$
|
0.25
|
|
|
$
|
11,201
|
|
|
October 14, 2016
|
December 31, 2016
|
December 31, 2017
|
December 31, 2018
|
December 31, 2019
|
||||||||||
Mammoth Energy Service, Inc.
|
$
|
100.00
|
|
$
|
114.63
|
|
$
|
148.04
|
|
$
|
135.60
|
|
$
|
16.59
|
|
S&P 500 Stock Index
|
$
|
100.00
|
|
$
|
104.88
|
|
$
|
125.25
|
|
$
|
117.44
|
|
$
|
151.35
|
|
Dow Jones Industrial Average Market Index
|
$
|
100.00
|
|
$
|
108.96
|
|
$
|
136.28
|
|
$
|
128.61
|
|
$
|
157.34
|
|
PHLX Oil Service Sector Index
|
$
|
100.00
|
|
$
|
111.51
|
|
$
|
90.74
|
|
$
|
48.90
|
|
$
|
47.50
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
STATEMENT OF COMPREHENSIVE INCOME (LOSS) DATA:
|
(in thousands, except per share data)
|
||||||||||||||||||
Total revenue
|
$
|
625,012
|
|
|
$
|
1,690,084
|
|
|
$
|
691,496
|
|
|
$
|
230,625
|
|
|
$
|
367,937
|
|
Total cost and expenses
|
$
|
753,395
|
|
|
$
|
1,295,633
|
|
|
$
|
628,725
|
|
|
$
|
265,255
|
|
|
$
|
383,710
|
|
Operating (loss) income
|
$
|
(128,383
|
)
|
|
$
|
394,451
|
|
|
$
|
62,771
|
|
|
$
|
(34,630
|
)
|
|
$
|
(15,773
|
)
|
Total other (income) expense
|
$
|
37,258
|
|
|
$
|
(5,223
|
)
|
|
$
|
(975
|
)
|
|
$
|
(3,938
|
)
|
|
$
|
(7,636
|
)
|
(Loss) income before income taxes
|
$
|
(91,125
|
)
|
|
$
|
389,228
|
|
|
$
|
61,796
|
|
|
$
|
(38,568
|
)
|
|
$
|
(23,409
|
)
|
Net (loss) income
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
$
|
58,964
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
Comprehensive (loss) income
|
$
|
(78,269
|
)
|
|
$
|
234,545
|
|
|
$
|
59,519
|
|
|
$
|
(89,742
|
)
|
|
$
|
(26,635
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net (loss) income per share (basic)
|
$
|
(1.76
|
)
|
|
$
|
5.27
|
|
|
$
|
1.42
|
|
|
$
|
(2.94
|
)
|
|
$
|
(0.73
|
)
|
Net (loss) income per share (diluted)
|
$
|
(1.76
|
)
|
|
$
|
5.24
|
|
|
$
|
1.42
|
|
|
$
|
(2.94
|
)
|
|
$
|
(0.73
|
)
|
Weighted average number of shares outstanding (basic)
|
45,011
|
|
|
44,750
|
|
|
41,548
|
|
|
31,500
|
|
|
30,000
|
|
|||||
Weighted average number of shares outstanding (diluted)
|
45,011
|
|
|
45,021
|
|
|
41,639
|
|
|
31,500
|
|
|
30,000
|
|
|||||
Cash dividends per common share
|
$
|
0.25
|
|
|
$
|
0.25
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Pro forma information (unaudited):
|
|
|
|
|
|
|
|
|
|
||||||||||
Net (loss) income, as reported
|
|
|
|
|
|
|
$
|
(92,453
|
)
|
|
$
|
(21,820
|
)
|
||||||
Taxes on income earned as a non-taxable entity
|
|
|
|
|
|
|
$
|
15,224
|
|
|
$
|
391
|
|
||||||
Taxes due to change to C corporation
|
|
|
|
|
|
|
$
|
53,089
|
|
|
$
|
—
|
|
||||||
Pro forma net loss
|
|
|
|
|
|
|
$
|
(24,140
|
)
|
|
$
|
(21,429
|
)
|
||||||
Pro forma loss per common share
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic and diluted
|
|
|
|
|
|
|
$
|
(0.56
|
)
|
|
$
|
(0.50
|
)
|
||||||
Weighted average pro forma shares outstanding—basic and diluted
|
|
|
|
|
|
|
43,107
|
|
|
43,107
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
||||||||||
CASH FLOW DATA:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash flows (used in) provided by operations
|
$
|
(95,318
|
)
|
|
$
|
386,668
|
|
|
$
|
57,616
|
|
|
$
|
29,689
|
|
|
$
|
69,639
|
|
Cash flows used in investing activities
|
$
|
(33,224
|
)
|
|
$
|
(211,955
|
)
|
|
$
|
(172,283
|
)
|
|
$
|
(7,718
|
)
|
|
$
|
(27,035
|
)
|
Cash flows provided by (used in) financing activities
|
$
|
66,702
|
|
|
$
|
(112,592
|
)
|
|
$
|
91,049
|
|
|
$
|
3,075
|
|
|
$
|
(55,557
|
)
|
|
December 31,
|
||||||||||||||||||
|
2019
|
|
2018
|
|
2017
|
|
2016
|
|
2015
|
||||||||||
BALANCE SHEET DATA:
|
(in thousands)
|
||||||||||||||||||
Cash and cash equivalents
|
$
|
5,872
|
|
|
$
|
67,625
|
|
|
$
|
5,637
|
|
|
$
|
29,239
|
|
|
$
|
4,039
|
|
Property, plant and equipment, net
|
$
|
352,772
|
|
|
$
|
436,699
|
|
|
$
|
351,017
|
|
|
$
|
242,120
|
|
|
$
|
294,883
|
|
Total assets
|
$
|
952,385
|
|
|
$
|
1,073,091
|
|
|
$
|
867,243
|
|
|
$
|
502,362
|
|
|
$
|
536,412
|
|
Total current liabilities
|
$
|
130,397
|
|
|
$
|
233,823
|
|
|
$
|
219,988
|
|
|
$
|
29,246
|
|
|
$
|
25,433
|
|
Long-term debt
|
$
|
80,000
|
|
|
$
|
—
|
|
|
$
|
99,900
|
|
|
$
|
—
|
|
|
$
|
95,000
|
|
Total liabilities
|
$
|
283,644
|
|
|
$
|
319,039
|
|
|
$
|
359,447
|
|
|
$
|
79,581
|
|
|
$
|
122,465
|
|
Total equity
|
$
|
668,741
|
|
|
$
|
754,052
|
|
|
$
|
507,796
|
|
|
$
|
422,781
|
|
|
$
|
413,947
|
|
•
|
Pressure Pumping—March 2012
|
•
|
Silverback Energy, formerly Logistics—November 2012
|
•
|
Barracuda—October 2014
|
•
|
Pumpdown—January 2015
|
•
|
Mr. Inspections—January 2015
|
•
|
Mammoth Equipment Leasing LLC—November 2016
|
•
|
Bison Sand Logistics LLC—January 2018
|
•
|
Aquahawk Energy LLC, or Aquahawk—June 2018
|
•
|
Cobra Acquisitions LLC, or Cobra—January 2017
|
•
|
Lion Power Services, formerly Cobra Energy LLC—January 2017
|
•
|
Higher Power Electrical LLC, or Higher Power—April 2017
|
•
|
5 Star Electric LLC, or 5 Star—July 2017
|
•
|
Dire Wolf Energy Services LLC—January 2018
|
•
|
Cobra Aviation LLC, or Cobra Aviation—January 2018
|
•
|
Cobra Logistics LLC—February 2018
|
•
|
Cobra Caribbean LLC—October 2018
|
•
|
Air Rescue Systems LLC, or ARS—December 2018
|
•
|
Python Equipment LLC—December 2018
|
•
|
Predator Aviation LLC—April 2019
|
•
|
Leopard Aviation—April 2019
|
•
|
Muskie Proppant—September 2011
|
•
|
Piranha Proppant LLC, or Piranha—May 2017
|
•
|
Sturgeon Acquisitions—June 2017
|
•
|
Taylor Frac—June 2017
|
•
|
Taylor Real Estate—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 LLC—March 2017
|
•
|
Sand Tiger—October 2007
|
•
|
Redback Energy Services—October 2011
|
•
|
Redback Coil Tubing—May 2012
|
•
|
WTL Oil LLC, or WTL, formerly Silverback—June 2016
|
•
|
Mammoth Energy Partners, LLC—June 2016
|
•
|
Stingray Energy Services LLC, or Stingray Energy Services—June 2017
|
•
|
Stingray Cementing LLC—June 2017
|
•
|
Tiger Shark Logistics LLC—October 2017
|
•
|
Black Mamba Energy LLC—March 2018
|
•
|
Stingray Cementing and Acidizing, formerly RTS Energy Services LLC—June 2018
|
•
|
Ivory Freight Solutions LLC—July 2018
|
•
|
IFX Transport LLC—December 2018
|
•
|
Anaconda Manufacturing LLC—September 2019
|
•
|
Aquawolf LLC—September 2019
|
•
|
Net loss of $79 million, or $1.76 per diluted share, and adjusted net loss of $38 million, or $0.85 per diluted share, for the year ended December 31, 2019. See “Non-GAAP Financial Measures” below for a reconciliation of net loss to adjusted net loss.
|
•
|
Adjusted EBITDA of $77 million for the year ended December 31, 2019. See “Non-GAAP Financial Measures” below for a reconciliation of net loss to Adjusted EBITDA.
|
•
|
Paid cash dividends of $0.25 per share. Beginning with the second quarter of 2019, we suspended the quarterly cash dividend in response to oilfield market conditions and other factors, which include collections from PREPA.
|
•
|
Formed an infrastructure engineering company focused on the transmission and distribution industry and commenced oilfield equipment manufacturing operations.
|
•
|
Hired a new president for our infrastructure division and recently added experienced industry personnel to key management positions.
|
|
Years Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
Revenue:
|
(in thousands)
|
||||||
Infrastructure services
|
$
|
214,449
|
|
|
$
|
1,082,371
|
|
Pressure pumping services
|
246,350
|
|
|
369,492
|
|
||
Natural sand proppant services
|
99,590
|
|
|
168,275
|
|
||
Drilling services
|
32,226
|
|
|
66,653
|
|
||
Other services
|
69,300
|
|
|
83,710
|
|
||
Eliminations
|
(36,903
|
)
|
|
(80,417
|
)
|
||
Total revenue
|
625,012
|
|
|
1,690,084
|
|
||
|
|
|
|
||||
Cost of revenue:
|
|
|
|
||||
Infrastructure services (exclusive of depreciation and amortization of $31,424 and $20,485, respectively, for 2019 and 2018)
|
171,756
|
|
|
610,600
|
|
||
Pressure pumping services (exclusive of depreciation and amortization of $40,198 and $51,417, respectively, for 2019 and 2018)
|
209,724
|
|
|
293,661
|
|
||
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $14,039 and $13,512, respectively, for 2019 and 2018)
|
90,179
|
|
|
132,817
|
|
||
Drilling services (exclusive of depreciation and amortization of $13,250 and $18,229, respectively, for 2019 and 2018)
|
36,809
|
|
|
60,802
|
|
||
Other services (exclusive of depreciation and amortization of $18,029 and $16,151, respectively, for 2019 and 2018)
|
72,283
|
|
|
76,314
|
|
||
Eliminations
|
(36,963
|
)
|
|
(80,390
|
)
|
||
Total cost of revenue
|
543,788
|
|
|
1,093,804
|
|
||
Selling, general and administrative expenses
|
51,552
|
|
|
73,097
|
|
||
Depreciation, depletion, amortization and accretion
|
117,033
|
|
|
119,877
|
|
||
Impairment of goodwill
|
33,664
|
|
|
3,203
|
|
||
Impairment of other long-lived assets
|
7,358
|
|
|
5,652
|
|
||
Operating (loss) income
|
(128,383
|
)
|
|
394,451
|
|
||
Interest expense, net
|
(4,958
|
)
|
|
(3,187
|
)
|
||
Other income (expense), net
|
42,216
|
|
|
(2,036
|
)
|
||
(Loss) income before income taxes
|
(91,125
|
)
|
|
389,228
|
|
||
(Benefit) provision for income taxes
|
(12,081
|
)
|
|
153,263
|
|
||
Net (loss) income
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
Years Ended
|
||||||
|
December 31, 2019
|
|
December 31, 2018
|
||||
Cash expenses:
|
|
|
|
||||
Compensation and benefits
|
$
|
19,364
|
|
|
$
|
42,950
|
|
Professional services
|
17,128
|
|
|
11,854
|
|
||
Other(a)
|
10,300
|
|
|
10,718
|
|
||
Total cash SG&A expense
|
46,792
|
|
|
65,522
|
|
||
Non-cash expenses:
|
|
|
|
||||
Bad debt provision(b)
|
1,434
|
|
|
(14,578
|
)
|
||
Equity based compensation(c)
|
—
|
|
|
17,487
|
|
||
Stock based compensation
|
3,326
|
|
|
4,666
|
|
||
Total non-cash SG&A expense
|
4,760
|
|
|
7,575
|
|
||
Total SG&A expense
|
$
|
51,552
|
|
|
$
|
73,097
|
|
a.
|
Includes travel-related costs, IT expenses, rent, utilities and other general and administrative-related costs.
|
b.
|
During the year ended December 31, 2018, we received payment for amounts previously reserved in 2017. As a result, during the year ended December 31, 2018, we reversed bad debt expense of $16 million recognized in 2017.
|
c.
|
Represents compensation expense for non-employee awards, which were issued and are payable by certain affiliates of Wexford (the sponsor level).
|
|
Years Ended
|
||||||
|
December 31, 2018
|
|
December 31, 2017
|
||||
Revenue:
|
(in thousands)
|
||||||
Infrastructure services
|
$
|
1,082,371
|
|
|
$
|
224,425
|
|
Pressure pumping services
|
369,492
|
|
|
279,352
|
|
||
Natural sand proppant services
|
168,275
|
|
|
117,037
|
|
||
Drilling services
|
66,653
|
|
|
50,521
|
|
||
Other services
|
83,710
|
|
|
51,728
|
|
||
Eliminations
|
(80,417
|
)
|
|
(31,567
|
)
|
||
Total revenue
|
1,690,084
|
|
|
691,496
|
|
||
|
|
|
|
||||
Cost of Revenue:
|
|
|
|
||||
Infrastructure services (exclusive of depreciation and amortization of $20,485 and $3,181, respectively, for 2018 and 2017)
|
610,600
|
|
|
121,560
|
|
||
Pressure pumping services (exclusive of depreciation and amortization of $51,417 and $45,381, respectively, for 2018 and 2017)
|
293,661
|
|
|
211,236
|
|
||
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $13,512 and $9,389, respectively, for 2018 and 2017)
|
132,817
|
|
|
92,780
|
|
||
Drilling services (exclusive of depreciation and amortization of $18,229 and $19,630, respectively, for 2018 and 2017)
|
60,802
|
|
|
46,847
|
|
||
Other services (exclusive of depreciation and amortization of $16,151 and $14,494, respectively, for 2018 and 2017)
|
76,314
|
|
|
41,678
|
|
||
Eliminations
|
(80,390
|
)
|
|
(31,532
|
)
|
||
Total cost of revenue
|
1,093,804
|
|
|
482,569
|
|
||
Selling, general and administrative expenses
|
73,097
|
|
|
49,886
|
|
||
Depreciation, depletion, amortization and accretion
|
119,877
|
|
|
92,124
|
|
||
Impairment of goodwill
|
3,203
|
|
|
—
|
|
||
Impairment of other long-lived assets
|
5,652
|
|
|
4,146
|
|
||
Operating income
|
394,451
|
|
|
62,771
|
|
||
Interest expense, net
|
(3,187
|
)
|
|
(4,310
|
)
|
||
Bargain purchase gain
|
—
|
|
|
4,012
|
|
||
Other expense, net
|
(2,036
|
)
|
|
(677
|
)
|
||
Income before income taxes
|
389,228
|
|
|
61,796
|
|
||
Provision for income taxes
|
153,263
|
|
|
2,832
|
|
||
Net income
|
$
|
235,965
|
|
|
$
|
58,964
|
|
|
Years Ended
|
||||||
|
December 31, 2018
|
|
December 31, 2017
|
||||
Cash expenses:
|
|
|
|
||||
Compensation and benefits
|
$
|
42,950
|
|
|
$
|
15,322
|
|
Professional services
|
11,854
|
|
|
7,765
|
|
||
Other(a)
|
10,718
|
|
|
7,503
|
|
||
Total cash SG&A expense
|
65,522
|
|
|
30,590
|
|
||
Non-cash expenses:
|
|
|
|
||||
Bad debt provision(b)
|
(14,578
|
)
|
|
16,098
|
|
||
Equity based compensation(c)
|
17,487
|
|
|
—
|
|
||
Stock based compensation
|
4,666
|
|
|
3,198
|
|
||
Total non-cash SG&A expense
|
7,575
|
|
|
19,296
|
|
||
Total SG&A expense
|
$
|
73,097
|
|
|
$
|
49,886
|
|
a.
|
Includes travel-related costs, IT expenses, rent, utilities and other general and administrative-related costs.
|
b.
|
During the year ended December 31, 2018, we received payment for amounts reserved in 2017. As a result, during the year ended December 31, 2018, we reversed bad debt expense of $16 million recognized in 2017.
|
c.
|
Represents compensation expense for non-employee awards, which were issued and are payable by certain affiliates of Wexford (the sponsor level).
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net (loss) income:
|
2019
|
|
2018
|
|
2017
|
||||||
Net (loss) income
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
$
|
58,964
|
|
Depreciation, depletion, amortization and accretion
|
117,033
|
|
|
119,877
|
|
|
92,124
|
|
|||
Impairment of goodwill
|
33,664
|
|
|
3,203
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
7,358
|
|
|
5,652
|
|
|
4,146
|
|
|||
Inventory obsolescence charges
|
1,349
|
|
|
—
|
|
|
—
|
|
|||
Acquisition related costs
|
45
|
|
|
191
|
|
|
2,506
|
|
|||
Public offering costs
|
—
|
|
|
982
|
|
|
—
|
|
|||
Equity based compensation
|
—
|
|
|
17,487
|
|
|
—
|
|
|||
Stock based compensation
|
4,177
|
|
|
5,425
|
|
|
3,741
|
|
|||
Bargain purchase gain
|
—
|
|
|
—
|
|
|
(4,012
|
)
|
|||
Interest expense, net
|
4,958
|
|
|
3,187
|
|
|
4,310
|
|
|||
Other (income) expense, net
|
(42,216
|
)
|
|
2,036
|
|
|
677
|
|
|||
(Benefit) provision for income taxes
|
(12,081
|
)
|
|
153,263
|
|
|
2,832
|
|
|||
Interest on delinquent accounts receivable
|
42,040
|
|
|
—
|
|
|
—
|
|
|||
Adjusted EBITDA
|
$
|
77,283
|
|
|
$
|
547,268
|
|
|
$
|
165,288
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income:
|
2019
|
|
2018
|
|
2017
|
||||||
Net income
|
$
|
17,108
|
|
|
$
|
319,940
|
|
|
$
|
48,537
|
|
Depreciation, depletion, amortization and accretion
|
31,451
|
|
|
20,516
|
|
|
3,185
|
|
|||
Impairment of goodwill
|
434
|
|
|
—
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
—
|
|
|
308
|
|
|
—
|
|
|||
Acquisition related costs
|
12
|
|
|
58
|
|
|
98
|
|
|||
Public offering costs
|
—
|
|
|
473
|
|
|
—
|
|
|||
Stock based compensation
|
870
|
|
|
2,089
|
|
|
345
|
|
|||
Interest expense
|
1,689
|
|
|
423
|
|
|
241
|
|
|||
Other (income) expense, net
|
(42,787
|
)
|
|
573
|
|
|
6
|
|
|||
Provision for income taxes
|
9,408
|
|
|
102,885
|
|
|
29,290
|
|
|||
Interest on delinquent accounts receivable
|
42,040
|
|
|
—
|
|
|
—
|
|
|||
Adjusted EBITDA
|
$
|
60,225
|
|
|
$
|
447,265
|
|
|
$
|
81,702
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2019
|
|
2018
|
|
2017
|
||||||
Net (loss) income
|
$
|
(39,893
|
)
|
|
$
|
(7,165
|
)
|
|
$
|
11,451
|
|
Depreciation, depletion, amortization and accretion
|
40,240
|
|
|
51,487
|
|
|
45,413
|
|
|||
Impairment of goodwill
|
23,423
|
|
|
—
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
—
|
|
|
143
|
|
|
—
|
|
|||
Acquisition related costs
|
18
|
|
|
39
|
|
|
1
|
|
|||
Public offering costs
|
—
|
|
|
264
|
|
|
—
|
|
|||
Equity based compensation
|
—
|
|
|
17,487
|
|
|
—
|
|
|||
Stock based compensation
|
1,700
|
|
|
1,612
|
|
|
1,641
|
|
|||
Interest expense
|
1,283
|
|
|
1,171
|
|
|
1,622
|
|
|||
Other expense, net
|
580
|
|
|
434
|
|
|
129
|
|
|||
Adjusted EBITDA
|
$
|
27,351
|
|
|
$
|
65,472
|
|
|
$
|
60,257
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2019
|
|
2018
|
|
2017
|
||||||
Net (loss) income
|
$
|
(12,589
|
)
|
|
$
|
14,962
|
|
|
$
|
9,474
|
|
Depreciation, depletion, amortization and accretion
|
14,050
|
|
|
13,519
|
|
|
9,394
|
|
|||
Impairment of goodwill
|
2,684
|
|
|
—
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
—
|
|
|
—
|
|
|
324
|
|
|||
Acquisition related costs
|
8
|
|
|
(38
|
)
|
|
2,163
|
|
|||
Public offering costs
|
—
|
|
|
144
|
|
|
—
|
|
|||
Stock based compensation
|
812
|
|
|
783
|
|
|
708
|
|
|||
Bargain purchase gain
|
—
|
|
|
—
|
|
|
(4,012
|
)
|
|||
Interest expense
|
193
|
|
|
234
|
|
|
679
|
|
|||
Other expense, net
|
67
|
|
|
525
|
|
|
211
|
|
|||
Benefit for income taxes
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||
Adjusted EBITDA
|
$
|
5,225
|
|
|
$
|
30,129
|
|
|
$
|
18,937
|
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2019
|
|
2018
|
|
2017
|
||||||
Net loss
|
$
|
(25,751
|
)
|
|
$
|
(22,987
|
)
|
|
$
|
(27,244
|
)
|
Depreciation, depletion, amortization and accretion
|
13,255
|
|
|
18,233
|
|
|
19,635
|
|
|||
Impairment of other long-lived assets
|
2,955
|
|
|
3,966
|
|
|
3,822
|
|
|||
Acquisition related costs
|
2
|
|
|
—
|
|
|
8
|
|
|||
Public offering costs
|
—
|
|
|
45
|
|
|
—
|
|
|||
Stock based compensation
|
361
|
|
|
576
|
|
|
507
|
|
|||
Interest expense, net
|
907
|
|
|
835
|
|
|
1,695
|
|
|||
Other (income) expense, net
|
(109
|
)
|
|
461
|
|
|
256
|
|
|||
Adjusted EBITDA
|
$
|
(8,380
|
)
|
|
$
|
1,129
|
|
|
$
|
(1,321
|
)
|
|
Years Ended December 31,
|
||||||||||
Reconciliation of Adjusted EBITDA to net income (loss):
|
2019
|
|
2018
|
|
2017
|
||||||
Net (loss) income
|
$
|
(17,980
|
)
|
|
$
|
(68,758
|
)
|
|
$
|
16,780
|
|
Depreciation, depletion, amortization and accretion
|
18,037
|
|
|
16,122
|
|
|
14,497
|
|
|||
Impairment of goodwill
|
7,123
|
|
|
3,203
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
4,403
|
|
|
1,235
|
|
|
—
|
|
|||
Inventory obsolescence charges
|
1,349
|
|
|
—
|
|
|
—
|
|
|||
Acquisition related costs
|
5
|
|
|
132
|
|
|
237
|
|
|||
Public offering costs
|
—
|
|
|
56
|
|
|
—
|
|
|||
Stock based compensation
|
434
|
|
|
365
|
|
|
539
|
|
|||
Interest expense, net
|
886
|
|
|
524
|
|
|
73
|
|
|||
Other expense, net
|
33
|
|
|
43
|
|
|
75
|
|
|||
(Benefit) provision for income taxes
|
(21,488
|
)
|
|
50,378
|
|
|
(26,454
|
)
|
|||
Adjusted EBITDA
|
$
|
(7,198
|
)
|
|
$
|
3,300
|
|
|
$
|
5,747
|
|
a.
|
Includes results for our coil tubing, pressure control, flowback, cementing, acidizing, equipment rentals, crude oil hauling, full service transportation and remote accommodations services and corporate related activities. Our corporate related activities do not generate revenue.
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
|
(in thousands, except per share amounts)
|
||||||||||
Net (loss) income, as reported
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
$
|
58,964
|
|
Impairment of goodwill
|
33,664
|
|
|
3,203
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
7,358
|
|
|
5,652
|
|
|
4,146
|
|
|||
Equity based compensation
|
—
|
|
|
17,487
|
|
|
—
|
|
|||
Adjusted net (loss) income
|
$
|
(38,022
|
)
|
|
$
|
262,307
|
|
|
$
|
63,110
|
|
|
|
|
|
|
|
||||||
Basic (loss) earnings per share, as reported
|
$
|
(1.76
|
)
|
|
$
|
5.27
|
|
|
$
|
1.42
|
|
Impairment of goodwill
|
0.75
|
|
|
0.07
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
0.16
|
|
|
0.13
|
|
|
0.10
|
|
|||
Equity based compensation
|
—
|
|
|
0.39
|
|
|
—
|
|
|||
Adjusted basic (loss) earnings per share
|
$
|
(0.85
|
)
|
|
$
|
5.86
|
|
|
$
|
1.52
|
|
|
|
|
|
|
|
||||||
Diluted (loss) earnings per share, as reported
|
$
|
(1.76
|
)
|
|
$
|
5.24
|
|
|
$
|
1.42
|
|
Impairment of goodwill
|
0.75
|
|
|
0.07
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
0.16
|
|
|
0.13
|
|
|
0.10
|
|
|||
Equity based compensation
|
—
|
|
|
0.39
|
|
|
—
|
|
|||
Adjusted diluted (loss) earnings per share
|
$
|
(0.85
|
)
|
|
$
|
5.83
|
|
|
$
|
1.52
|
|
|
December 31,
|
||||||
|
2019
|
|
2018
|
||||
Cash and cash equivalents
|
$
|
5,872
|
|
|
$
|
67,625
|
|
Revolving credit facility availability
|
184,809
|
|
|
184,233
|
|
||
Less borrowings
|
(80,000
|
)
|
|
—
|
|
||
Less letter of credit facilities (insurance programs)
|
(4,105
|
)
|
|
(4,105
|
)
|
||
Less letter of credit facilities (environmental remediation)
|
(4,182
|
)
|
|
(3,877
|
)
|
||
Less letter of credit facilities (rail car commitments)
|
(455
|
)
|
|
(455
|
)
|
||
Net working capital (less cash)(a)
|
270,711
|
|
|
148,108
|
|
||
Total
|
$
|
372,650
|
|
|
$
|
391,529
|
|
a.
|
Net working capital (less cash) is a non-GAAP measure and, as of December 31, 2019, is calculated by subtracting total current liabilities of $130 million and cash and cash equivalents of $6 million from total current assets of $407 million. As of December 31, 2018, net working capital (less cash) is calculated by subtracting total current liabilities of $234 million and cash and cash equivalents of $68 million from total current assets of $450 million.
|
|
Years Ended December 31,
|
||||||||
|
2019
|
2018
|
2017
|
||||||
Net cash (used in) provided by operating activities
|
$
|
(95,318
|
)
|
$
|
386,668
|
|
$
|
57,616
|
|
Net cash used in investing activities
|
(33,224
|
)
|
(211,955
|
)
|
(172,283
|
)
|
|||
Net cash provided by (used in) financing activities
|
66,702
|
|
(112,592
|
)
|
91,049
|
|
|||
Effect of foreign exchange rate on cash
|
87
|
|
(133
|
)
|
16
|
|
|||
Net change in cash
|
$
|
(61,753
|
)
|
$
|
61,988
|
|
$
|
(23,602
|
)
|
|
Years Ended December 31,
|
||||||||
|
2019
|
2018
|
2017
|
||||||
Infrastructure services(a)
|
$
|
5,643
|
|
$
|
100,701
|
|
$
|
20,144
|
|
Pressure pumping services(b)
|
14,703
|
|
33,774
|
|
85,853
|
|
|||
Natural sand proppant services(c)
|
2,877
|
|
17,935
|
|
16,376
|
|
|||
Drilling services(d)
|
3,156
|
|
13,398
|
|
8,927
|
|
|||
Other(e)
|
9,382
|
|
26,135
|
|
2,553
|
|
|||
Total capital expenditures
|
$
|
35,761
|
|
$
|
191,943
|
|
$
|
133,853
|
|
a.
|
Capital expenditures primarily for truck, tooling and equipment purchases for new infrastructure crews for the years ended December 31, 2019, 2018 and 2017.
|
b.
|
Capital expenditures primarily for pressure pumping equipment, including three new fleets, for the year ended December 31, 2017 and various pressure pumping and water transfer equipment for the years ended December 31, 2019 and 2018.
|
c.
|
Capital expenditures primarily for the upgrade and expansion of our plants for the years ended December 31, 2018 and 2017 and maintenance for the year ended December 31, 2019.
|
d.
|
Capital expenditures primarily for upgrades to our rig fleet and purchases of directional drilling equipment for the years ended December 31, 2019, 2018 and 2017.
|
e.
|
Capital expenditures primarily for equipment for our equipment rental and crude hauling businesses for the years ended December 31, 2019 and 2018 and various equipment for the year ended December 31, 2017.
|
•
|
the minimum interest coverage ratio of 3.0 to 1.0 was eliminated;
|
•
|
the maximum leverage coverage ratio of 4.0 to 1.0 was eliminated for the first two fiscal quarters of 2020 and, beginning with the fiscal quarter ended September 30, 2020, changed to 2.5 to 1.0;
|
•
|
beginning with the fiscal quarter ended September 30, 2020, a minimum fixed charge coverage ratio of at least 1.1 to 1.0 was added; and
|
•
|
from the effective date of February 26, 2020 through September 30, 2020, a minimum excess availability covenant of 10% of the maximum revolving advance amount was added.
|
|
Total
|
|
Less than 1 year
|
|
1-3 Years
|
|
3-5 Years
|
|
More than 5 Years
|
||||||||||
Contractual obligations:
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt(a)
|
$
|
80,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
80,000
|
|
|
$
|
—
|
|
Interest and commitment fees on long-term debt(b)
|
13,799
|
|
|
3,634
|
|
|
7,268
|
|
|
2,897
|
|
|
—
|
|
|||||
Operating lease obligations (c)
|
46,831
|
|
|
17,948
|
|
|
21,928
|
|
|
6,074
|
|
|
881
|
|
|||||
Financing lease obligations(d)
|
5,693
|
|
|
1,563
|
|
|
2,475
|
|
|
1,655
|
|
|
—
|
|
|||||
Equipment financing obligations(e)
|
1,952
|
|
|
731
|
|
|
1,213
|
|
|
8
|
|
|
—
|
|
|||||
Purchase commitments (f)
|
25,245
|
|
|
24,416
|
|
|
821
|
|
|
8
|
|
|
—
|
|
|||||
Capital purchase commitments (g)
|
4,865
|
|
|
4,865
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
$
|
178,385
|
|
|
$
|
53,157
|
|
|
$
|
33,705
|
|
|
$
|
90,642
|
|
|
$
|
881
|
|
a.
|
Excludes interest payments.
|
b.
|
Assumption of long-term debt balance outstanding as of December 31, 2019 of $80 million using the weighted average interest rate as of December 31, 2019 of 4.05%.
|
c.
|
Operating lease obligations primarily relate to rail cars, real estate and other equipment.
|
d.
|
Financing lease obligations primarily relate to equipment for our infrastructure segment.
|
e.
|
Equipment financing obligations primarily relate to vehicles and other equipment for our pressure pumping segment.
|
f.
|
Purchase commitments are comprised primarily of sand and coil tubing string. Included in these amounts are sand purchase commitments of $20 million. Pricing for certain sand purchase agreements is variable and, therefore, the total sand purchase commitments could be as much as $23 million. The minimum amount due in the form of shortfall fees under certain sand purchase agreements was $2 million as of December 31, 2019.
|
g.
|
Obligations arising from capital improvements/equipment purchases.
|
Year ended December 31:
|
Capital Spend Commitments
|
|
Minimum Purchase Commitments(a)
|
||||
2020
|
$
|
4,865
|
|
|
$
|
24,416
|
|
2021
|
—
|
|
|
697
|
|
||
2022
|
—
|
|
|
124
|
|
||
2023
|
—
|
|
|
8
|
|
||
2024
|
—
|
|
|
—
|
|
||
Thereafter
|
—
|
|
|
—
|
|
||
|
$
|
4,865
|
|
|
$
|
25,245
|
|
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, 2020
|
|
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, 2020
|
Arty Straehla
|
|
|
|
|
|
/s/ Mark Layton
|
Chief Financial Officer (principal financial and accounting officer)
|
February 28, 2020
|
Mark Layton
|
|
|
|
|
|
/s/ Arthur Amron
|
Director (Chairman of the Board)
|
February 28, 2020
|
Arthur Amron
|
|
|
|
|
|
/s/ Marc McCarthy
|
Director
|
February 28, 2020
|
Marc McCarthy
|
|
|
|
|
|
/s/ James D. Palm
|
Director
|
February 28, 2020
|
James D. Palm
|
|
|
|
|
|
/s/ Matthew Ross
|
Director
|
February 28, 2020
|
Matthew Ross
|
|
|
|
|
|
/s/ Arthur Smith
|
Director
|
February 28, 2020
|
Arthur Smith
|
|
|
|
|
|
/s/ Jonathan Yellen
|
Director
|
February 28, 2020
|
Jonathan Yellen
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017(a)
|
||||||
REVENUE
|
(in thousands, except per share amounts)
|
||||||||||
Services revenue
|
$
|
452,594
|
|
|
$
|
1,471,085
|
|
|
$
|
435,409
|
|
Services revenue - related parties
|
102,624
|
|
|
118,183
|
|
|
166,064
|
|
|||
Product revenue
|
42,105
|
|
|
75,766
|
|
|
47,067
|
|
|||
Product revenue - related parties
|
27,689
|
|
|
25,050
|
|
|
42,956
|
|
|||
Total revenue
|
625,012
|
|
|
1,690,084
|
|
|
691,496
|
|
|||
|
|
|
|
|
|
||||||
COST AND EXPENSES
|
|
|
|
|
|
||||||
Services cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $102,901, $106,282 and $82,686, respectively, for 2019, 2018 and 2017)
|
451,206
|
|
|
961,205
|
|
|
390,112
|
|
|||
Services cost of revenue - related parties (exclusive of depreciation, depletion, amortization and accretion of $0, $0 and $0, respectively, for 2019, 2018 and 2017)
|
4,770
|
|
|
5,885
|
|
|
1,408
|
|
|||
Product cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $14,039, $13,512 and $9,389, respectively, for 2019, 2018 and 2017)
|
87,812
|
|
|
126,714
|
|
|
91,049
|
|
|||
Selling, general and administrative (Note 13)
|
49,705
|
|
|
71,199
|
|
|
48,405
|
|
|||
Selling, general and administrative - related parties (Note 13)
|
1,847
|
|
|
1,898
|
|
|
1,481
|
|
|||
Depreciation, depletion, amortization and accretion
|
117,033
|
|
|
119,877
|
|
|
92,124
|
|
|||
Impairment of goodwill
|
33,664
|
|
|
3,203
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
7,358
|
|
|
5,652
|
|
|
4,146
|
|
|||
Total cost and expenses
|
753,395
|
|
|
1,295,633
|
|
|
628,725
|
|
|||
Operating (loss) income
|
(128,383
|
)
|
|
394,451
|
|
|
62,771
|
|
|||
|
|
|
|
|
|
||||||
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
||||||
Interest expense, net
|
(4,958
|
)
|
|
(3,187
|
)
|
|
(4,310
|
)
|
|||
Bargain purchase gain
|
—
|
|
|
—
|
|
|
4,012
|
|
|||
Other, net
|
42,216
|
|
|
(2,036
|
)
|
|
(677
|
)
|
|||
Total other income (expense)
|
37,258
|
|
|
(5,223
|
)
|
|
(975
|
)
|
|||
(Loss) income before income taxes
|
(91,125
|
)
|
|
389,228
|
|
|
61,796
|
|
|||
(Benefit) provision for income taxes
|
(12,081
|
)
|
|
153,263
|
|
|
2,832
|
|
|||
Net (loss) income
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
$
|
58,964
|
|
|
|
|
|
|
|
||||||
OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
||||||
Foreign currency translation adjustment, net of tax of ($203), $397 and $645, respectively, for 2019, 2018 and 2017
|
775
|
|
|
(1,420
|
)
|
|
555
|
|
|||
Comprehensive (loss) income
|
$
|
(78,269
|
)
|
|
$
|
234,545
|
|
|
$
|
59,519
|
|
|
|
|
|
|
|
||||||
Net (loss) income per share (basic) (Note 16)
|
$
|
(1.76
|
)
|
|
$
|
5.27
|
|
|
$
|
1.42
|
|
Net (loss) income per share (diluted) (Note 16)
|
$
|
(1.76
|
)
|
|
$
|
5.24
|
|
|
$
|
1.42
|
|
Weighted average number of shares outstanding (Note 16)
|
45,011
|
|
|
44,750
|
|
|
41,548
|
|
|||
Weighted average number of shares outstanding, including dilutive effect (Note 16)
|
45,011
|
|
|
45,021
|
|
|
41,639
|
|
|||
|
|
|
|
|
|
|
|||||
(a) Financial information includes the results attributable to Sturgeon for the entire period presented. See Note 4.
|
|
|
|
|
|
|
Accumulated
|
|
|||||||||||||
|
|
|
|
Retained
|
Additional
|
Other
|
|
|||||||||||||
|
Common Stock
|
Members'
|
Earnings
|
Paid-In
|
Comprehensive
|
|
||||||||||||||
|
Shares
|
Amount
|
Equity
|
(Deficit)
|
Capital
|
Loss
|
Total
|
|||||||||||||
|
(in thousands)
|
|||||||||||||||||||
Balance at January 1, 2017
|
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
|
)
|
||||||
Stock 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
|
|
|
Equity based compensation (Note 17)
|
—
|
|
—
|
|
—
|
|
—
|
|
17,487
|
|
—
|
|
17,487
|
|
||||||
Stock based compensation
|
288
|
|
3
|
|
—
|
|
—
|
|
5,422
|
|
—
|
|
5,425
|
|
||||||
Net income
|
—
|
|
—
|
|
—
|
|
235,965
|
|
—
|
|
—
|
|
235,965
|
|
||||||
Cash dividends declared ($0.25 per share)
|
—
|
|
—
|
|
—
|
|
(11,201
|
)
|
—
|
|
—
|
|
(11,201
|
)
|
||||||
Other comprehensive loss
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(1,420
|
)
|
(1,420
|
)
|
||||||
Balance at December 31, 2018
|
44,877
|
$
|
449
|
|
$
|
—
|
|
$
|
226,765
|
|
$
|
530,919
|
|
$
|
(4,081
|
)
|
$
|
754,052
|
|
|
Stock based compensation
|
232
|
|
2
|
|
—
|
|
—
|
|
4,175
|
|
—
|
|
4,177
|
|
||||||
Net loss
|
—
|
|
—
|
|
—
|
|
(79,044
|
)
|
—
|
|
—
|
|
(79,044
|
)
|
||||||
Cash dividends declared ($0.25 per share)
|
—
|
|
—
|
|
—
|
|
(11,219
|
)
|
—
|
|
—
|
|
(11,219
|
)
|
||||||
Other comprehensive income
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
775
|
|
775
|
|
||||||
Balance at December 31, 2019
|
45,109
|
$
|
451
|
|
$
|
—
|
|
$
|
136,502
|
|
$
|
535,094
|
|
$
|
(3,306
|
)
|
$
|
668,741
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017(a)
|
||||||
Cash flows from operating activities
|
(in thousands)
|
||||||||||
Net (loss) income
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
$
|
58,964
|
|
Adjustments to reconcile net (loss) income to cash (used in) provided by operating activities:
|
|
|
|
|
|
||||||
Equity based compensation (Note 17)
|
—
|
|
|
17,487
|
|
|
—
|
|
|||
Stock based compensation
|
4,177
|
|
|
5,425
|
|
|
3,741
|
|
|||
Depreciation, depletion, amortization and accretion
|
117,033
|
|
|
119,877
|
|
|
92,124
|
|
|||
Amortization of coil tubing strings
|
1,641
|
|
|
2,193
|
|
|
2,855
|
|
|||
Amortization of debt origination costs
|
326
|
|
|
387
|
|
|
399
|
|
|||
Bad debt expense (Note 2)
|
1,434
|
|
|
(14,578
|
)
|
|
16,206
|
|
|||
Loss on disposal of property and equipment
|
55
|
|
|
947
|
|
|
69
|
|
|||
Gain on bargain purchase
|
—
|
|
|
—
|
|
|
(4,012
|
)
|
|||
Impairment of goodwill
|
33,664
|
|
|
3,203
|
|
|
—
|
|
|||
Impairment of other long-lived assets
|
7,358
|
|
|
5,652
|
|
|
4,146
|
|
|||
Inventory obsolescence
|
1,349
|
|
|
—
|
|
|
—
|
|
|||
Deferred income taxes
|
(42,639
|
)
|
|
52,226
|
|
|
(34,425
|
)
|
|||
Other
|
(986
|
)
|
|
16
|
|
|
—
|
|
|||
Changes in assets and liabilities, net of acquisitions of businesses:
|
|
|
|
|
|
||||||
Accounts receivable, net
|
(27,006
|
)
|
|
(78,840
|
)
|
|
(231,751
|
)
|
|||
Receivables from related parties
|
3,641
|
|
|
22,624
|
|
|
(1,096
|
)
|
|||
Inventories
|
830
|
|
|
(5,502
|
)
|
|
(14,238
|
)
|
|||
Prepaid expenses and other assets
|
(1,040
|
)
|
|
1,423
|
|
|
(7,628
|
)
|
|||
Accounts payable
|
(25,968
|
)
|
|
(64,966
|
)
|
|
101,725
|
|
|||
Payables to related parties
|
156
|
|
|
(1,008
|
)
|
|
1,174
|
|
|||
Accrued expenses and other liabilities
|
(18,800
|
)
|
|
15,445
|
|
|
32,968
|
|
|||
Income taxes payable
|
(71,499
|
)
|
|
68,692
|
|
|
36,395
|
|
|||
Net cash (used in) provided by operating activities
|
(95,318
|
)
|
|
386,668
|
|
|
57,616
|
|
|||
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Purchases of property and equipment
|
(35,417
|
)
|
|
(187,285
|
)
|
|
(132,295
|
)
|
|||
Purchases of property and equipment from related parties
|
(344
|
)
|
|
(4,658
|
)
|
|
(1,558
|
)
|
|||
Business acquisitions, net
|
—
|
|
|
(20,824
|
)
|
|
(42,008
|
)
|
|||
Contributions to equity investee
|
(680
|
)
|
|
(702
|
)
|
|
—
|
|
|||
Proceeds from disposal of property and equipment
|
3,217
|
|
|
1,514
|
|
|
907
|
|
|||
Business combination cash acquired (Note 4)
|
—
|
|
|
—
|
|
|
2,671
|
|
|||
Net cash used in investing activities
|
(33,224
|
)
|
|
(211,955
|
)
|
|
(172,283
|
)
|
|||
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Borrowings on long-term debt
|
156,000
|
|
|
77,000
|
|
|
156,850
|
|
|||
Repayments of long-term debt
|
(76,000
|
)
|
|
(176,900
|
)
|
|
(56,950
|
)
|
|||
Dividends paid
|
(11,219
|
)
|
|
(11,201
|
)
|
|
—
|
|
|||
Principal payments on financing leases and equipment financing notes
|
(2,079
|
)
|
|
(292
|
)
|
|
—
|
|
|||
Debt issuance costs
|
—
|
|
|
(1,199
|
)
|
|
—
|
|
|||
Repayment of acquisition-related long-term debt
|
—
|
|
|
—
|
|
|
(8,851
|
)
|
|||
Net cash provided by (used in) financing activities
|
66,702
|
|
|
(112,592
|
)
|
|
91,049
|
|
|||
Effect of foreign exchange rate on cash
|
87
|
|
|
(133
|
)
|
|
16
|
|
|||
Net (decrease) increase in cash and cash equivalents
|
(61,753
|
)
|
|
61,988
|
|
|
(23,602
|
)
|
|||
Cash and cash equivalents at beginning of period
|
67,625
|
|
|
5,637
|
|
|
29,239
|
|
|||
Cash and cash equivalents at end of period
|
$
|
5,872
|
|
|
$
|
67,625
|
|
|
$
|
5,637
|
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017(a)
|
||||||
Supplemental disclosure of cash flow information:
|
(in thousands)
|
||||||||||
Cash paid for interest
|
$
|
4,741
|
|
|
$
|
3,212
|
|
|
$
|
3,656
|
|
Cash paid for income taxes
|
$
|
110,848
|
|
|
$
|
32,757
|
|
|
$
|
840
|
|
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
|
$
|
2,303
|
|
|
$
|
11,908
|
|
|
$
|
15,038
|
|
Right-of-use assets obtained for financing lease liabilities
|
$
|
3,721
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
||||||
(a) Financial information includes the results attributable to Sturgeon for the entire period presented. See Note 4.
|
1.
|
Organization and Basis of Presentation
|
|
December 31, 2019
|
|
December 31, 2018
|
||||||||
|
Share Count
|
|
% Ownership
|
|
Share Count
|
|
% Ownership
|
||||
Wexford
|
22,045,273
|
|
|
48.9
|
%
|
|
21,988,473
|
|
|
49.0
|
%
|
Gulfport
|
9,829,548
|
|
|
21.8
|
%
|
|
9,826,893
|
|
|
21.9
|
%
|
Rhino
|
—
|
|
|
—
|
%
|
|
104,100
|
|
|
0.2
|
%
|
Outstanding shares owned by related parties
|
31,874,821
|
|
|
70.7
|
%
|
|
31,919,466
|
|
|
71.1
|
%
|
Total outstanding
|
45,108,545
|
|
|
100.0
|
%
|
|
44,876,649
|
|
|
100.0
|
%
|
2.
|
Summary of Significant Accounting Policies
|
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
|
|
|
Additions charged to expense
|
|
(14,589
|
)
|
|
Deductions for uncollectible receivables written off
|
|
(1,950
|
)
|
|
Balance, December 31, 2018
|
|
5,198
|
|
|
Additions charged to expense
|
|
1,434
|
|
|
Deductions for uncollectible receivables written off
|
|
(1,478
|
)
|
|
Balance, December 31, 2019
|
|
$
|
5,154
|
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
Balance as of beginning of period
|
|
$
|
3,164
|
|
|
$
|
2,123
|
|
Additions
|
|
952
|
|
|
989
|
|
||
Accretion expense
|
|
120
|
|
|
60
|
|
||
Foreign currency translation adjustment
|
|
5
|
|
|
(8
|
)
|
||
Asset retirement obligation as of end of period
|
|
$
|
4,241
|
|
|
$
|
3,164
|
|
|
REVENUES
|
|
ACCOUNTS RECEIVABLE
|
||||||||
|
Years Ended December 31,
|
|
At December 31,
|
||||||||
|
2019
|
2018
|
2017
|
|
2019
|
2018
|
|||||
Customer A(a)
|
15
|
%
|
60
|
%
|
29
|
%
|
|
73
|
%
|
65
|
%
|
Customer B(b)
|
20
|
%
|
8
|
%
|
30
|
%
|
|
2
|
%
|
3
|
%
|
a.
|
Customer A is a third-party customer. Revenues and the related accounts receivable balances earned from Customer A were derived from the Company's infrastructure services segment. Accounts receivable for Customer A also includes receivables due for interest charged on delinquent accounts receivable.
|
b.
|
Customer B is a related party customer. Revenues and the related accounts receivable balances earned from Customer B were derived from the Company's pressure pumping services segment, natural sand proppant services segment and other businesses.
|
3.
|
Revenues
|
Balance, January 1, 2018
|
|
$
|
15,000
|
|
Deduction for recognition of revenue
|
|
(15,000
|
)
|
|
Increase for deferral of shortfall payments
|
|
4,246
|
|
|
Increase for deferral of customer prepayments
|
|
58
|
|
|
Balance, December 31, 2018
|
|
4,304
|
|
|
Deduction for recognition of revenue
|
|
(4,827
|
)
|
|
Increase for deferral of shortfall payments
|
|
8,442
|
|
|
Increase for deferral of customer prepayments
|
|
675
|
|
|
Deduction of shortfall payments due to contract renegotiations
|
|
(1,350
|
)
|
|
Balance, December 31, 2019
|
|
$
|
7,244
|
|
4.
|
Acquisitions
|
|
ARS
|
|
Brim Equipment Assets
|
||||
Accounts receivable
|
$
|
146
|
|
|
$
|
—
|
|
Property, plant and equipment
|
1,702
|
|
|
1,990
|
|
||
Identifiable intangible assets - trade name(a)
|
120
|
|
|
—
|
|
||
Goodwill(b)
|
694
|
|
|
2,243
|
|
||
Other non-current assets
|
5
|
|
|
—
|
|
||
Total assets acquired
|
$
|
2,667
|
|
|
$
|
4,233
|
|
a.
|
Trade name was valued using a “Relief-from-Royalty” method and will be amortized over 20 years.
|
b.
|
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.
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
||||||||
|
ARS
|
|
Brim Equipment Assets
|
||||||||||||
Revenues
|
$
|
2,153
|
|
|
$
|
—
|
|
|
$
|
2,616
|
|
|
$
|
—
|
|
Net loss(a)
|
(546
|
)
|
|
(25
|
)
|
|
(1,056
|
)
|
|
—
|
|
|
Years Ended December 31,
|
|
Years Ended December 31,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
ARS
|
|
Brim Equipment Assets
|
||||||||||||
Revenues
|
$
|
3,055
|
|
|
$
|
2,641
|
|
|
$
|
4,478
|
|
|
$
|
1,448
|
|
Net income (loss)
|
207
|
|
|
(39
|
)
|
|
2,410
|
|
|
459
|
|
|
|
WTL
|
||
Property, plant and equipment
|
|
$
|
2,960
|
|
Identifiable intangible assets - customer relationships(a)
|
|
930
|
|
|
Identifiable intangible assets - trade name(a)
|
|
650
|
|
|
Goodwill(b)
|
|
1,567
|
|
|
Total assets acquired
|
|
$
|
6,107
|
|
a.
|
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 10-20 years.
|
b.
|
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 the assembled workforce and future profitability expected to arise from the acquired entity.
|
|
2019
|
|
2018
|
||||
Revenues
|
$
|
8,413
|
|
|
$
|
7,511
|
|
Net loss(a)
|
(2,719
|
)
|
|
(149
|
)
|
|
|
RTS
|
||
Inventory
|
|
$
|
180
|
|
Property, plant and equipment
|
|
7,787
|
|
|
Goodwill(a)
|
|
133
|
|
|
Total assets acquired
|
|
$
|
8,100
|
|
|
2019
|
|
2018
|
||||
Revenues
|
$
|
2,456
|
|
|
$
|
6,682
|
|
Net loss(a)
|
(6,458
|
)
|
|
(3,210
|
)
|
|
|
5 Star
|
||
Accounts receivable
|
|
$
|
2,440
|
|
Property, plant and equipment
|
|
1,863
|
|
|
Identifiable intangible assets - trade names (a)
|
|
300
|
|
|
Goodwill (b)
|
|
248
|
|
|
Total assets acquired
|
|
$
|
4,851
|
|
|
|
|
||
Long-term debt and other liabilities
|
|
$
|
2,413
|
|
Total liabilities assumed
|
|
$
|
2,413
|
|
Net assets acquired
|
|
$
|
2,438
|
|
a.
|
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 10 years.
|
b.
|
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.
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues(a)
|
$
|
55,205
|
|
|
$
|
143,302
|
|
|
$
|
25,216
|
|
Net (loss) income (b)
|
(17,281
|
)
|
|
4,149
|
|
|
4,191
|
|
|
|
Year Ended
|
||
|
|
December 31, 2017
|
||
Revenues
|
|
$
|
31,548
|
|
Net income
|
|
3,910
|
|
|
|
Higher Power
|
||
Property, plant and equipment
|
|
$
|
1,744
|
|
Identifiable intangible assets - customer relationships
|
|
1,613
|
|
|
Goodwill (a)
|
|
643
|
|
|
Total assets acquired
|
|
$
|
4,000
|
|
a.
|
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.
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues(a)
|
$
|
93,379
|
|
|
$
|
220,281
|
|
|
$
|
39,571
|
|
Net (loss) income (b)
|
(33,195
|
)
|
|
(5,868
|
)
|
|
5,127
|
|
|
|
Year Ended
|
||
|
|
December 31, 2017
|
||
Revenues
|
|
$
|
42,343
|
|
Net income
|
|
5,004
|
|
|
|
Total
|
||
Property, plant and equipment (a)
|
|
$
|
23,373
|
|
Sand reserves (b)
|
|
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 (c, d)
|
|
(6,231
|
)
|
|
Total purchase price
|
|
$
|
36,320
|
|
a.
|
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.
|
b.
|
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.
|
c.
|
Amount in consolidated statements of comprehensive (loss) income reflected net of income taxes of $2.2 million.
|
d.
|
The fair value of the business was determined based on the excess cash flow method, a form of the income approach.
|
|
2019
|
|
2018
|
|
2017
|
||||||
Revenues(a)
|
$
|
27,617
|
|
|
$
|
52,628
|
|
|
$
|
22,847
|
|
Net (loss) income(b)
|
(3,513
|
)
|
|
8,379
|
|
|
5,520
|
|
|
|
Year Ended
|
||
|
|
December 31, 2017
|
||
Revenues
|
|
$
|
22,847
|
|
Net income
|
|
5,655
|
|
Consideration attributable to Cementing (a)
|
|
$
|
12,975
|
|
Consideration attributable to SR Energy (a)
|
|
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(a)
|
|
13,061
|
|
7,459
|
|
|
20,520
|
|
|||
Identifiable intangible assets - customer relationships(b)
|
|
—
|
|
1,140
|
|
|
1,140
|
|
|||
Identifiable intangible assets - trade names(b)
|
|
550
|
|
270
|
|
|
820
|
|
|||
Goodwill(c)
|
|
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 (d)
|
|
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
|
|
a.
|
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.
|
b.
|
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.
|
c.
|
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.
|
d.
|
Long-term debt assumed was paid off subsequent to the acquisition.
|
|
2019
|
|
2018
|
|
2017
|
|||||||||||||||
|
SR Energy
|
Cementing
|
|
SR Energy
|
Cementing
|
|
SR Energy
|
Cementing
|
||||||||||||
Revenues(a)
|
$
|
36,600
|
|
$
|
618
|
|
|
$
|
29,287
|
|
$
|
6,426
|
|
|
$
|
11,572
|
|
$
|
7,500
|
|
Net loss(b, c)
|
(3,975
|
)
|
(2,449
|
)
|
|
(2,539
|
)
|
(5,869
|
)
|
|
(1,626
|
)
|
(1,963
|
)
|
a.
|
Includes intercompany revenues of $2.3 million, $3.0 million and $0.6 million, respectively, for SR Energy for 2019, 2018 and 2017 and $0.6 million, $0.3 million and a nominal amount, respectively, for Cementing for 2019, 2018 and 2017.
|
b.
|
Includes depreciation and amortization of $4.9 million, $5.4 million and $3.4 million, respectively, for SR Energy for 2019, 2018 and 2017 and $0.8 million, $1.5 million and $4.1 million, respectively, for Cementing for 2019, 2018 and 2017.
|
c.
|
Includes non-cash impairment expense of $3.9 million for SR Energy in 2019 and $3.1 million and $4.4 million, respectively, for Cementing in 2019 and 2018.
|
|
|
Year Ended
|
||
|
|
December 31, 2017
|
||
Revenues
|
|
$
|
35,142
|
|
Net loss
|
|
(4,066
|
)
|
5.
|
Inventories
|
6.
|
Property, Plant and Equipment
|
|
|
|
December 31,
|
||||||
|
Useful Life
|
|
2019
|
|
2018
|
||||
Pressure pumping equipment
|
3-5 years
|
|
$
|
216,627
|
|
|
$
|
208,968
|
|
Drilling rigs and related equipment
|
3-15 years
|
|
117,783
|
|
|
122,198
|
|
||
Machinery and equipment
|
7-20 years
|
|
190,221
|
|
|
173,867
|
|
||
Buildings(a)
|
15-39 years
|
|
47,859
|
|
|
46,380
|
|
||
Vehicles, trucks and trailers
|
5-10 years
|
|
135,724
|
|
|
132,337
|
|
||
Coil tubing equipment
|
4-10 years
|
|
29,438
|
|
|
29,128
|
|
||
Land
|
N/A
|
|
13,687
|
|
|
14,235
|
|
||
Land improvements
|
15 years or life of lease
|
|
10,135
|
|
|
9,614
|
|
||
Rail improvements
|
10-20 years
|
|
13,802
|
|
|
13,806
|
|
||
Other property and equipment(a)
|
3-12 years
|
|
18,880
|
|
|
18,551
|
|
||
|
|
|
794,156
|
|
|
769,084
|
|
||
Deposits on equipment and equipment in process of assembly(b)
|
|
|
6,627
|
|
|
16,865
|
|
||
|
|
|
800,783
|
|
|
785,949
|
|
||
Less: accumulated depreciation(c)
|
|
|
448,011
|
|
|
349,250
|
|
||
Total property, plant and equipment, net
|
|
|
$
|
352,772
|
|
|
$
|
436,699
|
|
a.
|
Included in Buildings and Other property and equipment at December 31, 2019 are costs of $6.7 million and $6.5 million, respectively, related to assets under operating leases.
|
b.
|
Deposits on equipment and equipment in process of assembly represents deposits placed with vendors for equipment that is in the process of assembly and purchased equipment that is being outfitted for its intended use. The equipment is not yet placed in service.
|
c.
|
Includes accumulated depreciation of $3.5 million at December 31, 2019 related to assets under operating leases.
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
Depreciation expense
|
|
$
|
112,435
|
|
|
$
|
107,634
|
|
|
$
|
81,191
|
|
Accretion and depletion expense (see Note 2)
|
|
3,477
|
|
|
3,539
|
|
|
1,632
|
|
|||
Amortization expense (see Note 8)
|
|
1,121
|
|
|
8,704
|
|
|
9,301
|
|
|||
Depreciation, depletion, amortization and accretion
|
|
$
|
117,033
|
|
|
$
|
119,877
|
|
|
$
|
92,124
|
|
7.
|
Impairments
|
|
December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Drilling rigs and related equipment
|
$
|
2,955
|
|
|
$
|
3,966
|
|
|
$
|
3,822
|
|
Other property, plant and equipment
|
3,557
|
|
|
307
|
|
|
324
|
|
|||
Intangible assets
|
846
|
|
|
1,379
|
|
|
—
|
|
|||
|
$
|
7,358
|
|
|
$
|
5,652
|
|
|
$
|
4,146
|
|
8.
|
Goodwill and Intangible Assets
|
|
Infrastructure
|
|
Pressure Pumping
|
|
Sand
|
|
Other
|
|
Total
|
||||||||||
Balance as of January 1, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Goodwill
|
$
|
891
|
|
|
$
|
86,043
|
|
|
$
|
2,684
|
|
|
$
|
10,193
|
|
|
$
|
99,811
|
|
Accumulated impairment losses
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
|
891
|
|
|
86,043
|
|
|
2,684
|
|
|
10,193
|
|
|
99,811
|
|
|||||
Acquisitions
|
2,937
|
|
|
—
|
|
|
—
|
|
|
1,700
|
|
|
4,637
|
|
|||||
Impairment losses(a)
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,203
|
)
|
|
(3,203
|
)
|
|||||
Balance as of December 31, 2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Goodwill
|
3,828
|
|
|
86,043
|
|
|
2,684
|
|
|
11,893
|
|
|
104,448
|
|
|||||
Accumulated impairment losses
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,203
|
)
|
|
(3,203
|
)
|
|||||
|
3,828
|
|
|
86,043
|
|
|
2,684
|
|
|
8,690
|
|
|
101,245
|
|
|||||
Acquisitions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Impairment losses(a)
|
(434
|
)
|
|
(23,423
|
)
|
|
(2,684
|
)
|
|
(7,123
|
)
|
|
(33,664
|
)
|
|||||
Balance as of December 31, 2019
|
|
|
|
|
|
|
|
|
|
||||||||||
Goodwill
|
3,828
|
|
|
86,043
|
|
|
2,684
|
|
|
11,893
|
|
|
104,448
|
|
|||||
Accumulated impairment losses
|
(434
|
)
|
|
(23,423
|
)
|
|
(2,684
|
)
|
|
(10,326
|
)
|
|
(36,867
|
)
|
|||||
|
$
|
3,394
|
|
|
$
|
62,620
|
|
|
$
|
—
|
|
|
$
|
1,567
|
|
|
$
|
67,581
|
|
a.
|
See Note 7 for a description of impairment losses recognized.
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
Customer relationships
|
|
$
|
1,050
|
|
|
$
|
2,255
|
|
Trade names
|
|
9,063
|
|
|
9,063
|
|
||
Less: accumulated amortization - customer relationships
|
|
(467
|
)
|
|
(544
|
)
|
||
Less: accumulated amortization - trade names
|
|
(3,858
|
)
|
|
(3,018
|
)
|
||
Intangible assets, net
|
|
$
|
5,788
|
|
|
$
|
7,756
|
|
Year ended December 31:
|
|
Amount
|
||
2020
|
|
$
|
1,015
|
|
2021
|
|
1,015
|
|
|
2022
|
|
1,015
|
|
|
2023
|
|
898
|
|
|
2024
|
|
771
|
|
|
Thereafter
|
|
1,074
|
|
|
|
|
$
|
5,788
|
|
9.
|
Equity Method Investment
|
10.
|
Accrued Expenses and Other Current Liabilities
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
State and local taxes payable
|
|
$
|
15,288
|
|
|
18,687
|
|
|
Deferred revenue
|
|
7,244
|
|
|
4,304
|
|
||
Financed insurance premiums
|
|
6,463
|
|
|
6,761
|
|
||
Accrued compensation, benefits and related taxes
|
|
5,938
|
|
|
20,898
|
|
||
Insurance reserves
|
|
2,906
|
|
|
4,678
|
|
||
Other
|
|
2,915
|
|
|
4,324
|
|
||
Total
|
|
$
|
40,754
|
|
|
$
|
59,652
|
|
11.
|
Debt
|
•
|
the minimum interest coverage ratio of 3.0 to 1.0 was eliminated;
|
•
|
the maximum leverage coverage ratio of 4.0 to 1.0 was eliminated for the first two fiscal quarters of 2020 and, beginning with the fiscal quarter ended September 30, 2020, changed to 2.5 to 1.0;
|
•
|
beginning with the fiscal quarter ended September 30, 2020, a minimum fixed charge coverage ratio of at least 1.1 to 1.0 was added; and
|
•
|
from the effective date of February 26, 2020 through September 30, 2020, a minimum excess availability covenant of 10% of the maximum revolving advance amount was added.
|
12.
|
Variable Interest Entities
|
13.
|
Selling, General and Administrative Expense
|
|
Years Ended December 31,
|
||||||||||
|
2019
|
|
2018
|
|
2017
|
||||||
Cash expenses:
|
|
|
|
|
|
||||||
Compensation and benefits
|
$
|
19,364
|
|
|
$
|
42,950
|
|
|
$
|
15,322
|
|
Professional services
|
17,128
|
|
|
11,854
|
|
|
7,765
|
|
|||
Other(a)
|
10,300
|
|
|
10,718
|
|
|
7,503
|
|
|||
Total cash SG&A expense
|
46,792
|
|
|
65,522
|
|
|
30,590
|
|
|||
Non-cash expenses:
|
|
|
|
|
|
||||||
Bad debt provision(b)
|
1,434
|
|
|
(14,578
|
)
|
|
16,098
|
|
|||
Equity based compensation(c)
|
—
|
|
|
17,487
|
|
|
—
|
|
|||
Stock based compensation
|
3,326
|
|
|
4,666
|
|
|
3,198
|
|
|||
Total non-cash SG&A expense
|
4,760
|
|
|
7,575
|
|
|
19,296
|
|
|||
Total SG&A expense
|
$
|
51,552
|
|
|
$
|
73,097
|
|
|
$
|
49,886
|
|
a.
|
Includes travel-related costs, IT expenses, rent, utilities and other general and administrative-related costs.
|
b.
|
During the year ended December 31, 2018, the Company received payment for amounts previously reserved in 2017. As a result, during the year ended December 31, 2018, the Company reversed bad debt expense of $16.0 million recognized in 2017.
|
c.
|
Represents compensation expense for non-employee awards, which were issued and are payable by certain affiliates of Wexford (the sponsor level). See Note 17 for additional detail.
|
14.
|
Income Taxes
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
U.S. current income tax expense
|
|
$
|
386
|
|
|
$
|
25,656
|
|
|
$
|
804
|
|
U.S. deferred income tax (benefit) expense
|
|
(21,761
|
)
|
|
25,372
|
|
|
(27,764
|
)
|
|||
Foreign current income tax expense
|
|
30,172
|
|
|
75,381
|
|
|
36,565
|
|
|||
Foreign deferred income tax (benefit) expense
|
|
(20,878
|
)
|
|
26,854
|
|
|
(6,773
|
)
|
|||
Total
|
|
$
|
(12,081
|
)
|
|
$
|
153,263
|
|
|
$
|
2,832
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
(Loss) income before income taxes, as reported
|
|
$
|
(91,125
|
)
|
|
$
|
389,228
|
|
|
$
|
61,796
|
|
Bargain purchase gain, net of tax
|
|
—
|
|
|
—
|
|
|
(4,012
|
)
|
|||
(Loss) income before income taxes, as taxed
|
|
(91,125
|
)
|
|
389,228
|
|
|
57,784
|
|
|||
Statutory income tax rate
|
|
21
|
%
|
|
21
|
%
|
|
35
|
%
|
|||
Expected income tax (benefit) expense
|
|
(19,136
|
)
|
|
81,738
|
|
|
20,224
|
|
|||
Change in tax rate
|
|
—
|
|
|
(103
|
)
|
|
(21,309
|
)
|
|||
Tax reform - unrepatriated foreign earnings
|
|
—
|
|
|
—
|
|
|
(9,727
|
)
|
|||
Foreign income tax rate differential
|
|
9,387
|
|
|
39,080
|
|
|
6,286
|
|
|||
Foreign earnings not in reported income
|
|
12,581
|
|
|
46,834
|
|
|
22,054
|
|
|||
Foreign tax credits
|
|
(26,141
|
)
|
|
(89,677
|
)
|
|
(29,551
|
)
|
|||
Withholding taxes
|
|
3,635
|
|
|
13,930
|
|
|
—
|
|
|||
Goodwill impairment
|
|
6,506
|
|
|
675
|
|
|
—
|
|
|||
Other permanent differences
|
|
1,873
|
|
|
12,370
|
|
|
503
|
|
|||
State tax expenses
|
|
2,364
|
|
|
5,394
|
|
|
39
|
|
|||
Return to provision
|
|
(15,156
|
)
|
|
6,071
|
|
|
—
|
|
|||
Other
|
|
—
|
|
|
680
|
|
|
(1,192
|
)
|
|||
Change in valuation allowance
|
|
12,006
|
|
|
36,271
|
|
|
15,505
|
|
|||
Total
|
|
$
|
(12,081
|
)
|
|
$
|
153,263
|
|
|
$
|
2,832
|
|
|
|
Year Ended December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
Deferred tax assets:
|
|
|
|
|
||||
Allowance for doubtful accounts
|
|
$
|
1,189
|
|
|
$
|
1,180
|
|
Lease asset
|
|
11,105
|
|
|
—
|
|
||
Deferred compensation
|
|
—
|
|
|
1,032
|
|
||
Accrued liabilities
|
|
950
|
|
|
3,428
|
|
||
Net operating loss carryover
|
|
4,180
|
|
|
467
|
|
||
Foreign tax credits
|
|
76,060
|
|
|
51,776
|
|
||
Other
|
|
1,633
|
|
|
1,627
|
|
||
Valuation allowance
|
|
(63,783
|
)
|
|
(51,776
|
)
|
||
Deferred tax assets
|
|
31,334
|
|
|
7,734
|
|
||
|
|
|
|
|
||||
Deferred tax liabilities:
|
|
|
|
|
||||
Property and equipment
|
|
$
|
(55,180
|
)
|
|
$
|
(63,181
|
)
|
Intangible assets
|
|
—
|
|
|
(4,936
|
)
|
||
Withholding taxes
|
|
—
|
|
|
(17,419
|
)
|
||
Lease liability
|
|
(11,151
|
)
|
|
—
|
|
||
Other
|
|
(1,876
|
)
|
|
(1,507
|
)
|
||
Deferred tax liabilities
|
|
(68,207
|
)
|
|
(87,043
|
)
|
||
Net deferred tax liability
|
|
$
|
(36,873
|
)
|
|
$
|
(79,309
|
)
|
|
|
|
|
|
||||
Reflected in accompanying balance sheet as:
|
|
|
|
|
||||
Deferred income tax asset
|
|
$
|
—
|
|
|
$
|
—
|
|
Deferred income tax liability
|
|
(36,873
|
)
|
|
(79,309
|
)
|
||
Total
|
|
$
|
(36,873
|
)
|
|
$
|
(79,309
|
)
|
15.
|
Leases
|
|
Year Ended December 31, 2019
|
||
Operating lease expense
|
$
|
21,643
|
|
Short-term lease expense
|
682
|
|
|
Finance lease expense:
|
|
||
Amortization of right-of-use assets
|
1,134
|
|
|
Interest on lease liabilities
|
192
|
|
|
Total lease expense
|
$
|
23,651
|
|
|
December 31, 2019
|
||
Operating leases:
|
|
||
Operating lease right-of-use assets
|
$
|
43,446
|
|
Current operating lease liability
|
16,432
|
|
|
Long-term operating lease liability
|
27,102
|
|
|
Finance leases:
|
|
||
Property and equipment, net
|
$
|
5,111
|
|
Accrued expenses and other current liabilities
|
1,365
|
|
|
Other liabilities
|
3,856
|
|
|
Year Ended December 31, 2019
|
||
Cash paid for amounts included in the measurement of lease liabilities:
|
|
||
Operating cash flows from operating leases
|
$
|
21,375
|
|
Operating cash flows from finance leases
|
192
|
|
|
Financing cash flows from finance leases
|
1,503
|
|
|
Right-of-use assets obtained in exchange for lease obligations:
|
|
||
Operating leases
|
$
|
5,548
|
|
Finance leases
|
3,721
|
|
|
December 31, 2019
|
|
Weighted-average remaining lease term:
|
|
|
Operating leases
|
3.4 years
|
|
Finance leases
|
4.1 years
|
|
Weighted-average discount rate:
|
|
|
Operating leases
|
4.4
|
%
|
Finance leases
|
4.3
|
%
|
|
Operating Leases
|
|
Finance Leases
|
||||
2020
|
$
|
17,948
|
|
|
$
|
1,563
|
|
2021
|
13,181
|
|
|
1,254
|
|
||
2022
|
8,747
|
|
|
1,221
|
|
||
2023
|
4,353
|
|
|
1,214
|
|
||
2024
|
1,721
|
|
|
441
|
|
||
Thereafter
|
881
|
|
|
—
|
|
||
Total lease payments
|
46,831
|
|
|
5,693
|
|
||
Less: Present value discount
|
3,297
|
|
|
472
|
|
||
Present value of lease payments
|
$
|
43,534
|
|
|
$
|
5,221
|
|
16.
|
Dividends and Earnings (Loss) Per Share
|
|
Per Share
|
|
Total
|
||||
|
|
|
(in thousands)
|
||||
2019
|
|
|
|
||||
Paid on February 14, 2019
|
$
|
0.125
|
|
|
$
|
5,609
|
|
Paid on May 17, 2019
|
0.125
|
|
|
5,610
|
|
||
Total cash dividends
|
$
|
0.25
|
|
|
$
|
11,219
|
|
2018
|
|
|
|
||||
Paid on August 14, 2018
|
$
|
0.125
|
|
|
$
|
5,595
|
|
Paid on November 15, 2018
|
0.125
|
|
|
5,606
|
|
||
Total cash dividends
|
$
|
0.25
|
|
|
$
|
11,201
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
|
|
(in thousands, except per share data)
|
||||||||||
Basic (loss) earnings per share:
|
|
|
|
|
|
|
||||||
Allocation of earnings:
|
|
|
|
|
|
|
||||||
Net (loss) income
|
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
$
|
58,964
|
|
Weighted average common shares outstanding
|
|
45,011
|
|
|
44,750
|
|
|
41,548
|
|
|||
Basic (loss) earnings per share
|
|
$
|
(1.76
|
)
|
|
$
|
5.27
|
|
|
$
|
1.42
|
|
|
|
|
|
|
|
|
||||||
Diluted (loss) earnings per share:
|
|
|
|
|
|
|
||||||
Allocation of earnings:
|
|
|
|
|
|
|
||||||
Net (loss) income
|
|
$
|
(79,044
|
)
|
|
$
|
235,965
|
|
|
$
|
58,964
|
|
Weighted average common shares, including dilutive effect (a)
|
|
45,011
|
|
|
45,021
|
|
|
41,639
|
|
|||
Diluted (loss) earnings per share
|
|
$
|
(1.76
|
)
|
|
$
|
5.24
|
|
|
$
|
1.42
|
|
a.
|
No incremental shares of potentially dilutive restricted stock awards were included for the year ended December 31, 2019 as their effect was antidilutive under the treasury stock method.
|
17.
|
Equity Based Compensation
|
18.
|
Stock-Based Compensation
|
|
|
Number of Unvested Restricted Stock Units
|
|
Weighted Average Grant-Date Fair Value
|
|||
Unvested restricted stock units as of January 1, 2017
|
|
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
|
|
Granted
|
|
103,556
|
|
|
$
|
27.74
|
|
Vested
|
|
(270,069
|
)
|
|
$
|
19.26
|
|
Forfeited
|
|
(40,000
|
)
|
|
$
|
20.68
|
|
Unvested restricted stock units as of December 31, 2018
|
|
434,119
|
|
|
$
|
22.78
|
|
Granted
|
|
101,181
|
|
|
$
|
6.83
|
|
Vested
|
|
(231,896
|
)
|
|
$
|
22.45
|
|
Forfeited
|
|
(82,163
|
)
|
|
$
|
18.55
|
|
Unvested restricted stock units as of December 31, 2019
|
|
221,241
|
|
|
$
|
22.43
|
|
19.
|
Related Party Transactions
|
|
|
REVENUES
|
|
ACCOUNTS RECEIVABLE
|
|||||||||||||
|
|
Years Ended December 31,
|
|
At December 31,
|
|||||||||||||
|
|
2019
|
2018
|
2017
|
|
2019
|
2018
|
||||||||||
Stingray Pressure Pumping and Gulfport
|
(a)
|
$
|
90,357
|
|
$
|
96,013
|
|
$
|
144,473
|
|
|
$
|
5,950
|
|
$
|
8,175
|
|
Muskie and Gulfport
|
(b)
|
27,689
|
|
25,050
|
|
42,956
|
|
|
1,141
|
|
1,193
|
|
|||||
SR Energy and Gulfport
|
(c)
|
8,772
|
|
14,717
|
|
10,129
|
|
|
156
|
|
1,658
|
|
|||||
Aquahawk and Gulfport
|
(d)
|
828
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
|||||
Panther and Gulfport
|
(e)
|
—
|
|
44
|
|
3,253
|
|
|
—
|
|
—
|
|
|||||
Cementing and Gulfport
|
(f)
|
—
|
|
5,853
|
|
7,410
|
|
|
—
|
|
—
|
|
|||||
Cobra Aviation/ARS/Leopard and Brim Equipment
|
(g)
|
2,093
|
|
—
|
|
—
|
|
|
235
|
|
—
|
|
|||||
Panther and El Toro
|
(h)
|
573
|
|
918
|
|
96
|
|
|
—
|
|
64
|
|
|||||
Other Relationships
|
|
1
|
|
638
|
|
703
|
|
|
41
|
|
74
|
|
|||||
|
|
$
|
130,313
|
|
$
|
143,233
|
|
$
|
209,020
|
|
|
$
|
7,523
|
|
$
|
11,164
|
|
a.
|
Stingray 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.
|
SR Energy provides rental services for Gulfport.
|
d.
|
Aquahawk provides water transfer services for Gulfport pursuant to a master services agreement.
|
e.
|
Panther performs drilling services for Gulfport pursuant to a master service agreement.
|
f.
|
Cementing performs well cementing services for Gulfport.
|
g.
|
Cobra Aviation, ARS and Leopard lease helicopters to Brim Equipment pursuant to aircraft lease and management agreements.
|
h.
|
Panther provides directional drilling services for El Toro, an affiliate of Wexford, pursuant to a master service agreement.
|
|
|
COST OF REVENUE
|
|
ACCOUNTS PAYABLE
|
|||||||||||||
|
|
Years Ended December 31,
|
|
At December 31,
|
|||||||||||||
|
|
2019
|
2018
|
2017
|
|
2019
|
2018
|
||||||||||
Cobra Aviation/ARS/Leopard and Brim Equipment
|
(a)
|
4,720
|
|
—
|
|
—
|
|
|
433
|
|
—
|
|
|||||
Cobra and T&E
|
(b)
|
—
|
|
4,042
|
|
610
|
|
|
—
|
|
—
|
|
|||||
Higher Power and T&E
|
(b)
|
—
|
|
1,603
|
|
25
|
|
|
—
|
|
—
|
|
|||||
Panther and DBDHT
|
(c)
|
—
|
|
240
|
|
196
|
|
|
|
240
|
|
||||||
The Company and 2017 Stingray Companies
|
(d)
|
—
|
|
—
|
|
432
|
|
|
—
|
|
—
|
|
|||||
Other Relationships
|
|
50
|
|
—
|
|
145
|
|
|
—
|
|
—
|
|
|||||
|
|
$
|
4,770
|
|
$
|
5,885
|
|
$
|
1,408
|
|
|
$
|
433
|
|
$
|
240
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
SELLING, GENERAL AND ADMINISTRATIVE COSTS
|
|
|
|
||||||||||||
The Company and Wexford
|
(e)
|
650
|
|
992
|
|
892
|
|
|
1
|
|
100
|
|
|||||
The Company and Caliber
|
(f)
|
785
|
|
648
|
|
335
|
|
|
7
|
|
3
|
|
|||||
Cobra Aviation/ARS/Leopard and Brim Equipment
|
(a)
|
233
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
|||||
Other Relationships
|
|
179
|
|
258
|
|
254
|
|
|
9
|
|
27
|
|
|||||
|
|
$
|
1,847
|
|
$
|
1,898
|
|
$
|
1,481
|
|
|
$
|
17
|
|
$
|
130
|
|
|
|
|
|
|
|
|
|
||||||||||
|
|
CAPITAL EXPENDITURES
|
|
|
|
||||||||||||
Leopard and Brim Equipment
|
(a)
|
420
|
|
—
|
|
—
|
|
|
76
|
|
—
|
|
|||||
Cobra and T&E
|
(b)
|
—
|
|
1,247
|
|
629
|
|
|
—
|
|
—
|
|
|||||
Higher Power and T&E
|
(b)
|
—
|
|
2,960
|
|
1,380
|
|
|
—
|
|
—
|
|
|||||
|
|
$
|
420
|
|
$
|
4,207
|
|
$
|
2,009
|
|
|
$
|
76
|
|
$
|
—
|
|
|
|
|
|
|
|
$
|
526
|
|
$
|
370
|
|
a.
|
Cobra Aviation, ARS and Leopard lease helicopters to Brim Equipment pursuant to aircraft lease and management agreements.
|
b.
|
Cobra and Higher Power purchased materials and services from T&E, an entity in which a member of management's family owned a minority interest. T&E ceased to be a related party as of September 30, 2018.
|
c.
|
Panther rents rotary steerable equipment in connection with its directional drilling services from DBDHT, 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.
|
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.
|
f.
|
The Company leases office space from Caliber, an entity controlled by Wexford.
|
20.
|
Commitments and Contingencies
|
Year ended December 31:
|
Capital Spend Commitments
|
|
Minimum Purchase Commitments(a)
|
||||
2020
|
$
|
4,865
|
|
|
$
|
24,416
|
|
2021
|
—
|
|
|
697
|
|
||
2022
|
—
|
|
|
124
|
|
||
2023
|
—
|
|
|
8
|
|
||
2024
|
—
|
|
|
—
|
|
||
Thereafter
|
—
|
|
|
—
|
|
||
|
$
|
4,865
|
|
|
$
|
25,245
|
|
a.
|
Included in these amounts are sand purchase commitments of $19.5 million. Pricing for certain sand purchase agreements is variable and, therefore, the total sand purchase commitments could be as much as $23.1 million. The minimum amount due in the form of shortfall fees under certain sand purchase agreements was $1.8 million as of December 31, 2019.
|
|
|
December 31,
|
||||||
|
|
2019
|
|
2018
|
||||
Environmental remediation
|
|
$
|
4,182
|
|
|
$
|
3,877
|
|
Insurance programs
|
|
4,105
|
|
|
4,105
|
|
||
Rail car commitments
|
|
455
|
|
|
455
|
|
||
Total letters of credit
|
|
$
|
8,742
|
|
|
$
|
8,437
|
|
21.
|
Reporting Segments and Geographic Areas
|
Year Ended December 31, 2019
|
Infrastructure
|
Pressure Pumping
|
Sand
|
Drilling
|
All Other
|
Eliminations
|
Total
|
||||||||||||||
Revenue from external customers
|
$
|
214,449
|
|
$
|
241,972
|
|
$
|
69,794
|
|
$
|
31,728
|
|
$
|
67,069
|
|
$
|
—
|
|
$
|
625,012
|
|
Intersegment revenues
|
—
|
|
4,378
|
|
29,796
|
|
498
|
|
2,231
|
|
(36,903
|
)
|
—
|
|
|||||||
Total revenue
|
214,449
|
|
246,350
|
|
99,590
|
|
32,226
|
|
69,300
|
|
(36,903
|
)
|
625,012
|
|
|||||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
171,756
|
|
177,997
|
|
87,637
|
|
35,963
|
|
70,435
|
|
—
|
|
543,788
|
|
|||||||
Intersegment cost of revenues
|
—
|
|
31,727
|
|
2,542
|
|
846
|
|
1,848
|
|
(36,963
|
)
|
—
|
|
|||||||
Total cost of revenue
|
171,756
|
|
209,724
|
|
90,179
|
|
36,809
|
|
72,283
|
|
(36,963
|
)
|
543,788
|
|
|||||||
Selling, general and administrative
|
25,390
|
|
10,993
|
|
5,006
|
|
4,160
|
|
6,003
|
|
—
|
|
51,552
|
|
|||||||
Depreciation, depletion, amortization and accretion
|
31,451
|
|
40,240
|
|
14,050
|
|
13,255
|
|
18,037
|
|
—
|
|
117,033
|
|
|||||||
Impairment of goodwill
|
434
|
|
23,423
|
|
2,684
|
|
—
|
|
7,123
|
|
—
|
|
33,664
|
|
|||||||
Impairment of other long-lived assets
|
—
|
|
—
|
|
—
|
|
2,955
|
|
4,403
|
|
—
|
|
7,358
|
|
|||||||
Operating income (loss)
|
(14,582
|
)
|
(38,030
|
)
|
(12,329
|
)
|
(24,953
|
)
|
(38,549
|
)
|
60
|
|
(128,383
|
)
|
|||||||
Interest expense
|
1,689
|
|
1,283
|
|
193
|
|
907
|
|
886
|
|
—
|
|
4,958
|
|
|||||||
Other expense
|
(42,787
|
)
|
580
|
|
67
|
|
(109
|
)
|
33
|
|
—
|
|
(42,216
|
)
|
|||||||
Income (loss) before income taxes
|
$
|
26,516
|
|
$
|
(39,893
|
)
|
$
|
(12,589
|
)
|
$
|
(25,751
|
)
|
$
|
(39,468
|
)
|
$
|
60
|
|
$
|
(91,125
|
)
|
Total expenditures for property, plant and equipment
|
$
|
5,643
|
|
$
|
14,703
|
|
$
|
2,877
|
|
$
|
3,156
|
|
$
|
9,382
|
|
$
|
—
|
|
$
|
35,761
|
|
As of December 31, 2019:
|
|
|
|
|
|
|
|
||||||||||||||
Intangible assets, net
|
$
|
1,410
|
|
$
|
3,371
|
|
$
|
—
|
|
$
|
—
|
|
$
|
1,007
|
|
$
|
—
|
|
$
|
5,788
|
|
Total assets
|
$
|
420,285
|
|
$
|
175,259
|
|
$
|
190,382
|
|
$
|
61,545
|
|
$
|
142,731
|
|
$
|
(37,817
|
)
|
$
|
952,385
|
|
Year Ended December 31, 2018
|
Infrastructure
|
Pressure Pumping
|
Sand
|
Drilling
|
All Other
|
Eliminations
|
Total
|
||||||||||||||
Revenue from external customers
|
$
|
1,082,371
|
|
$
|
362,491
|
|
$
|
100,816
|
|
$
|
66,237
|
|
$
|
78,169
|
|
$
|
—
|
|
$
|
1,690,084
|
|
Intersegment revenue
|
—
|
|
7,001
|
|
67,459
|
|
416
|
|
5,541
|
|
(80,417
|
)
|
—
|
|
|||||||
Total revenue
|
1,082,371
|
|
369,492
|
|
168,275
|
|
66,653
|
|
83,710
|
|
(80,417
|
)
|
1,690,084
|
|
|||||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
608,017
|
|
223,296
|
|
126,714
|
|
60,248
|
|
75,529
|
|
—
|
|
1,093,804
|
|
|||||||
Intersegment cost of revenues
|
2,583
|
|
70,365
|
|
6,103
|
|
554
|
|
785
|
|
(80,390
|
)
|
—
|
|
|||||||
Total cost of revenue
|
610,600
|
|
293,661
|
|
132,817
|
|
60,802
|
|
76,314
|
|
(80,390
|
)
|
1,093,804
|
|
|||||||
Selling, general and administrative(a)
|
27,126
|
|
29,761
|
|
6,218
|
|
5,343
|
|
4,649
|
|
—
|
|
73,097
|
|
|||||||
Depreciation and amortization
|
20,516
|
|
51,487
|
|
13,519
|
|
18,233
|
|
16,122
|
|
—
|
|
119,877
|
|
|||||||
Impairment of goodwill
|
—
|
|
—
|
|
—
|
|
—
|
|
3,203
|
|
—
|
|
3,203
|
|
|||||||
Impairment of other long-lived assets
|
308
|
|
143
|
|
—
|
|
3,966
|
|
1,235
|
|
—
|
|
5,652
|
|
|||||||
Operating income (loss)
|
423,821
|
|
(5,560
|
)
|
15,721
|
|
(21,691
|
)
|
(17,813
|
)
|
(27
|
)
|
394,451
|
|
|||||||
Interest expense
|
423
|
|
1,171
|
|
234
|
|
835
|
|
524
|
|
—
|
|
3,187
|
|
|||||||
Other expense
|
573
|
|
434
|
|
525
|
|
461
|
|
43
|
|
—
|
|
2,036
|
|
|||||||
Income (loss) before income taxes
|
$
|
422,825
|
|
$
|
(7,165
|
)
|
$
|
14,962
|
|
$
|
(22,987
|
)
|
$
|
(18,380
|
)
|
$
|
(27
|
)
|
$
|
389,228
|
|
Total expenditures for property, plant and equipment
|
$
|
100,701
|
|
$
|
33,774
|
|
$
|
17,935
|
|
$
|
13,398
|
|
$
|
26,135
|
|
$
|
—
|
|
$
|
191,943
|
|
As of December 31, 2018:
|
|
|
|
|
|
|
|
||||||||||||||
Intangible assets, net
|
$
|
1,650
|
|
$
|
4,059
|
|
$
|
—
|
|
$
|
—
|
|
$
|
2,047
|
|
$
|
—
|
|
$
|
7,756
|
|
Total assets
|
$
|
366,457
|
|
$
|
254,278
|
|
$
|
177,870
|
|
$
|
83,714
|
|
$
|
132,309
|
|
$
|
58,463
|
|
$
|
1,073,091
|
|
Year Ended December 31, 2017
|
Infrastructure
|
Pressure Pumping
|
Sand
|
Drilling
|
All Other
|
Eliminations
|
Total
|
||||||||||||||
Revenue from external customers
|
$
|
224,425
|
|
$
|
277,326
|
|
$
|
90,023
|
|
$
|
50,075
|
|
$
|
49,647
|
|
$
|
—
|
|
$
|
691,496
|
|
Intersegment revenues
|
—
|
|
2,026
|
|
27,014
|
|
446
|
|
2,081
|
|
(31,567
|
)
|
—
|
|
|||||||
Total revenue
|
224,425
|
|
279,352
|
|
117,037
|
|
50,521
|
|
51,728
|
|
(31,567
|
)
|
691,496
|
|
|||||||
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion
|
120,117
|
|
183,089
|
|
91,049
|
|
46,701
|
|
41,613
|
|
—
|
|
482,569
|
|
|||||||
Intersegment cost of revenues
|
1,443
|
|
28,147
|
|
1,731
|
|
146
|
|
65
|
|
(31,532
|
)
|
—
|
|
|||||||
Total cost of revenue
|
121,560
|
|
211,236
|
|
92,780
|
|
46,847
|
|
41,678
|
|
(31,532
|
)
|
482,569
|
|
|||||||
Selling, general and administrative
|
21,606
|
|
9,501
|
|
8,190
|
|
5,510
|
|
5,079
|
|
—
|
|
49,886
|
|
|||||||
Depreciation, depletion, amortization and accretion
|
3,185
|
|
45,413
|
|
9,394
|
|
19,635
|
|
14,497
|
|
—
|
|
92,124
|
|
|||||||
Impairment of long-lived assets
|
—
|
|
—
|
|
324
|
|
3,822
|
|
—
|
|
—
|
|
4,146
|
|
|||||||
Operating loss
|
78,074
|
|
13,202
|
|
6,349
|
|
(25,293
|
)
|
(9,526
|
)
|
(35
|
)
|
62,771
|
|
|||||||
Interest expense
|
241
|
|
1,622
|
|
679
|
|
1,695
|
|
73
|
|
—
|
|
4,310
|
|
|||||||
Bargain purchase gain
|
—
|
|
—
|
|
(4,012
|
)
|
—
|
|
—
|
|
—
|
|
(4,012
|
)
|
|||||||
Other expense (income)
|
6
|
|
129
|
|
211
|
|
256
|
|
75
|
|
—
|
|
677
|
|
|||||||
(Loss) income before income taxes
|
$
|
77,827
|
|
$
|
11,451
|
|
$
|
9,471
|
|
$
|
(27,244
|
)
|
$
|
(9,674
|
)
|
$
|
(35
|
)
|
$
|
61,796
|
|
Total expenditures for property, plant and equipment
|
20,144
|
|
85,853
|
|
16,376
|
|
8,927
|
|
2,553
|
|
—
|
|
133,853
|
|
|||||||
As of December 31, 2017:
|
|
|
|
|
|
|
|
||||||||||||||
Intangible assets, net
|
$
|
1,770
|
|
$
|
12,392
|
|
$
|
—
|
|
$
|
—
|
|
$
|
1,977
|
|
$
|
—
|
|
$
|
16,139
|
|
Total assets
|
$
|
205,275
|
|
$
|
297,140
|
|
$
|
190,859
|
|
$
|
88,527
|
|
$
|
243,767
|
|
$
|
(158,325
|
)
|
$
|
867,243
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2019
|
|
2018
|
|
2017
|
||||||
United States
|
|
$
|
516,276
|
|
|
$
|
654,506
|
|
|
$
|
471,745
|
|
Puerto Rico
|
|
96,630
|
|
|
1,022,558
|
|
|
203,087
|
|
|||
Canada
|
|
11,946
|
|
|
13,020
|
|
|
16,664
|
|
|||
Other
|
|
160
|
|
|
—
|
|
|
—
|
|
|||
Total
|
|
$
|
625,012
|
|
|
$
|
1,690,084
|
|
|
$
|
691,496
|
|
|
Three Months Ended
|
|
|||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
Total
|
||||||||||
|
2019
|
2019
|
2019
|
2019
|
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Revenue
|
$
|
262,138
|
|
$
|
181,820
|
|
$
|
113,417
|
|
$
|
67,637
|
|
$
|
625,012
|
|
Gross profit (loss)
|
73,068
|
|
13,805
|
|
2,283
|
|
(7,932
|
)
|
81,224
|
|
|||||
Net income (loss)
|
28,333
|
|
(10,889
|
)
|
(35,709
|
)
|
(60,779
|
)
|
(79,044
|
)
|
|||||
|
|
|
|
|
|
||||||||||
Net income (loss) per share (basic)
|
$
|
0.63
|
|
$
|
(0.24
|
)
|
$
|
(0.79
|
)
|
$
|
(1.35
|
)
|
$
|
(1.76
|
)
|
Net income (loss) per share (diluted)
|
$
|
0.63
|
|
$
|
(0.24
|
)
|
$
|
(0.79
|
)
|
$
|
(1.35
|
)
|
$
|
(1.76
|
)
|
|
Three Months Ended
|
|
|||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
Total
|
||||||||||
|
2018
|
2018
|
2018
|
2018
|
|
||||||||||
|
(in thousands, except per share data)
|
||||||||||||||
Revenue
|
$
|
494,249
|
|
$
|
533,594
|
|
$
|
384,043
|
|
$
|
278,198
|
|
$
|
1,690,084
|
|
Gross profit
|
168,148
|
|
193,766
|
|
136,478
|
|
97,888
|
|
596,280
|
|
|||||
Net income
|
55,546
|
|
42,700
|
|
69,512
|
|
68,207
|
|
235,965
|
|
|||||
|
|
|
|
|
|
||||||||||
Net income per share (basic)
|
$
|
1.24
|
|
$
|
0.95
|
|
$
|
1.55
|
|
$
|
1.52
|
|
$
|
5.27
|
|
Net income per share (diluted)
|
$
|
1.24
|
|
$
|
0.95
|
|
$
|
1.54
|
|
$
|
1.51
|
|
$
|
5.24
|
|
23.
|
Subsequent Events
|
•
|
the terms of redemption and the amount of, and provisions regarding, any sinking fund for the purchase or redemption thereof;
|
•
|
the liquidation preferences and the amounts payable on dissolution or liquidation;
|
•
|
the terms and conditions under which shares of the series may or shall be converted into any other series or class of stock or debt of the corporation; and
|
•
|
any other terms or provisions which the board of directors is legally authorized to fix or alter.
|
•
|
permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested so long as it has been approved by our board of directors;
|
•
|
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.
|
EXCESS AVAILABILITY
|
APPLICABLE MARGINS FOR LIBOR RATE LOANS
|
APPLICABLE MARGINS FOR DOMESTIC RATE LOANS
|
If the Usage Amount is less than $40,000,000
|
3.00%
|
2.00%
|
If Excess Availability is the Usage Amount is equal to or greater than $40,000,000 but equal to or less than $75,000,000
|
3.25%
|
2.25%
|
If the Usage Amount is greater than $75,000,000
|
3.50%
|
2.50%
|
PNC BANK, NATIONAL ASSOCIATION,
as Lender and as Agent
|
By: /s/ Brad Higgins
Name: Brad Higgins
Title: Senior Vice President
Commitment Percentage: 54.054054%
Commitment Amount: $70,270,270.27 |
|
BARCLAYS BANK PLC,
as a Lender
|
By: /s/ Sydney G. Dennis
Name: Sydney G. Dennis
Title: Director
Commitment Percentage: 18.918919%
Commitment Amount: $24,594,594.59
CREDIT SUISSE AG, Cayman Islands Branch,
as a Lender
|
UMB BANK, N.A.,
as a Lender
|
By: /s/ Stuart Sullivan
Name: Stuart Sullivan
Title: Senior Vice President
Commitment Percentage: 13.513514%
Commitment Amount: $17,567,567.57 |
Name of Subsidiary
|
5 Star Electric LLC
|
Air Rescue Systems Corporation
|
Anaconda Manufacturing LLC
|
Aquahawk Energy LLC
|
Aquawolf LLC
|
Barracuda Logistics LLC
|
Bison Drilling and Field Services LLC
|
Bison Trucking LLC
|
Cobra Acquisitions LLC
|
Cobra Aviation LLC
|
Lion Power Services LLC
|
Dire Wolf Energy Services LLC
|
Great White Sand Tiger Lodging Ltd.
|
Higher Power Electrical LLC
|
IFX Transport LLC
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Ivory Freight Solutions LLC
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Leopard Aviation LLC
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Mako Acquisitions LLC
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Mammoth Energy Partners LLC
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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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Predator Aviation LLC
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Python Equipment 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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Stingray Cementing and Acidizing LLC
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Silverback Energy 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 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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WTL Oil 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, 2020
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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:
|
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.
|
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, 2020
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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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|
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MAMMOTH ENERGY SERVICES, INC.
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|
By:
|
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/s/ Arty Straehla
|
|
|
|
Arty Straehla
|
|
|
|
Chief Executive Officer
|
|
|
|
February 28, 2020
|
|
|
|
|
1.
|
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.
|
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.
|
|
By:
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/s/ Mark Layton
|
|
|
|
Mark Layton
|
|
|
|
Chief Financial Officer
|
|
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February 28, 2020
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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)
|
Section 104
S&S
Citations(#)
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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 (b)($, amounts in dollars)
|
Mining Related Fatalities (#)
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||||||||
Taylor, WI
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1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
$
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832
|
|
—
|
|
Plum City, WI
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
$
|
—
|
|
—
|
|
New Auburn, WI
|
2
|
|
1
|
|
—
|
|
—
|
|
—
|
|
$
|
1,280
|
|
—
|
|
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.
|
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, 2019.
|