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GLOSSARY OF OIL AND NATURAL GAS AND ELECTRICAL INFRASTRUCTURE TERMS


The following is a glossary of certain oil and natural gas and natural sand proppant industry terms used in this Annual Report on Form 10-K (this “annual report” or “report”):
Acidizing			To pump acid into a wellbore to improve well productivity or injectivity.
Blowout			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.
Bottomhole assembly			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.
Cementing			To prepare and pump cement into place in a wellbore.
Coiled tubing			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.
Completion			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.
Directional drilling			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.
Down-hole			Pertaining to or in the wellbore (as opposed to being on the surface).
Down-hole motor			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.
Drilling rig			The machine used to drill a wellbore.
Drillpipe or Drill pipe			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.
Drillstring or Drill string			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.
Flowback			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.
Horizontal drilling			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.
Hydraulic fracturing			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.
Hydrocarbon			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.


Mesh size			The size of the proppant that is determined by sieving the proppant through screens with uniform openings corresponding to the desired size of the proppant. Each type of proppant comes in various sizes, categorized as mesh sizes, and the various mesh sizes are used in different applications in the oil and natural gas industry. The mesh number system is a measure of the number of equally sized openings per square inch of screen through which the proppant is sieved.
Mud motors			A positive displacement drilling motor that uses hydraulic horsepower of the drilling fluid to drive the drill bit. Mud motors are used extensively in directional drilling operations.
Natural gas liquids			Components of natural gas that are liquid at surface in field facilities or in gas processing plants. Natural gas liquids can be classified according to their vapor pressures as low (condensate), intermediate (natural gasoline) and high (liquefied petroleum gas) vapor pressure.
Nitrogen pumping unit			A high-pressure pump or compressor unit capable of delivering high-purity nitrogen gas for use in oil or gas wells. Two basic types of units are commonly available: a nitrogen converter unit that pumps liquid nitrogen at high pressure through a heat exchanger or converter to deliver high-pressure gas at ambient temperature, and a nitrogen generator unit that compresses and separates air to provide a supply of high pressure nitrogen gas.
Plugging			The process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Plugging work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging work.
Plug			A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.
Pounds per square inch			A unit of pressure. It is the pressure resulting from a one pound force applied to an area of one square inch.
Pressure pumping			Services that include the pumping of liquids under pressure.
Producing formation			An underground rock formation from which oil, natural gas or water is produced. Any porous rock will contain fluids of some sort, and all rocks at considerable distance below the Earth’s surface will initially be under pressure, often related to the hydrostatic column of ground waters above the reservoir. To produce, rocks must also have permeability, or the capacity to permit fluids to flow through them.
Proppant			Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.
Resource play			Accumulation of hydrocarbons known to exist over a large area.
Shale			A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.
Tight oil			Conventional oil that is found within reservoirs with very low permeability. The oil contained within these reservoir rocks typically will not flow to the wellbore at economic rates without assistance from technologically advanced drilling and completion processes. Commonly, horizontal drilling coupled with multistage fracturing is used to access these difficult to produce reservoirs.
Tight sands			A type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.
Tubulars			A generic term pertaining to any type of oilfield pipe, such as drill pipe, drill collars, pup joints, casing, production tubing and pipeline.
Unconventional resource/unconventional well			A term for the different manner by which resources are exploited as compared to the extraction of conventional resources. In unconventional drilling, the wellbore is generally drilled to specific objectives within narrow parameters, often across long, lateral intervals within narrow horizontal formations offering greater contact area with the producing formation. Typically, the well is then hydraulically fractured at multiple stages to optimize production.
Wellbore			The physical conduit from surface into the hydrocarbon reservoir.
Well stimulation			A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.
Wireline			A general term used to describe well-intervention operations conducted using single-strand or multi-strand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term commonly is used in association with electric logging and cables incorporating electrical conductors.
Workover			The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.

The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors, which are difficult to predict and many of which are beyond our control. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this annual report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the many factors including those described in Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this annual report. All forward-looking statements speak only as of the date of this annual report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

We are an integrated, growth-oriented energy services company focused on providing products and services to enable the exploration and development of North American onshore unconventional oil and natural gas reserve as well as the construction and repair of the electric grid for private utilities, public investor-owned utilities and co-operative utilities through our infrastructure services businesses. Our primary business objective is to grow our operations and create value for stockholders through organic growth opportunities and accretive acquisitions. Our suite of services includes well completion services, infrastructure services, natural sand proppant services, drilling services and other services. Our well completion services division provides hydraulic fracturing, sand hauling and water transfer services. Our infrastructure services division provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells natural sand proppant used for hydraulic fracturing. Our drilling services division currently provides rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. In addition to these service divisions, we also provide aviation services, equipment rentals, remote accommodations and equipment manufacturing. We believe that the services we offer play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources as well as in maintaining and improving electrical infrastructure. Our complementary suite of services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

We also provide logistics solutions to facilitate delivery of our frac sand products to our customers. Our frac sand products are primarily shipped by rail to our customers in the Utica Shale, SCOOP/STACK, DJ Basin, Permian Basin and the Montney Shale in British Columbia and Alberta, Canada. Our logistics capabilities are important to our customers, who focus on both the reliability and flexibility of product delivery. Because our customers generally find it impractical to store frac sand in large quantities near their well completion sites, they typically prefer product to be delivered where and as needed, which requires predictable and efficient loading and shipping capabilities. We contract with third party providers to transport our frac sand products to railroad facilities for delivery to our customers. We currently lease or have access to origin transloading facilities on the Canadian National Railway Company (CN), Union Pacific (UP), Burlington Northern Santa Fe (BNSF) and the Canadian Pacific (CP) rail systems and use an in-house railcar fleet that we lease from various third parties to deliver our frac sand products to our customers. Origin transloading facilities on multiple railways allow us to provide predictable and efficient loading and shipping of our frac sand products. We also utilize a destination transloading facility in Yorkville, Ohio, to serve the Utica Shale, and utilize destination transloading facilities located in other North American resource plays, including the Montney Shale, to meet our customers’ delivery needs.

Coil Tubing. We provided coil tubing services in Eagle Ford Shale and Permian Basin. Coiled tubing services involve injecting coiled tubing into wells to perform various well-servicing and workover operations. Coiled tubing is a flexible steel pipe with a diameter of typically less than three inches and manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck-mounted reel for onshore applications. Due to its small diameter in certain iterations, coiled tubing can be inserted into existing production tubing and used to perform a variety of services to enhance the flow of oil or natural gas without using a larger, more costly workover rig. The principal advantages of using coiled tubing in a workover include the ability to (i) continue production from the well without interruption, thus reducing the risk of formation damage, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe in the case of a workover rig, which must be jointed and unjointed, (iii) direct fluids into a wellbore with more precision, allowing for improved stimulation fluid placement, (iv) provide a source of energy to power a downhole mud motor or manipulate down-hole tools and (v) enhance access to remote fields due to the smaller size and mobility of a coiled tubing unit. As of December 31, 2022, we owned one coiled tubing unit capable of running 25,000 feet of two and five eighths inch coil rated at 15,000 pounds per square inch, or psi, two coiled tubing units capable of running 23,500 feet of two and three eighths inch coil rated at 15,000 psi, one coiled tubing unit capable of running 24,500 feet of two inch coil rated at 15,000 psi, two coiled tubing units capable of running 22,500 feet of two inch coil rated at 10,000 psi and one coiled tubing unit capable of running 20,500 feet of two and three eighths inch coil rated at 15,000 psi.

Demand for most of our oil and natural gas products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The levels of capital expenditures of our customers are predominantly driven by the prices of oil and natural gas. In March and April 2020, concurrent with the COVID-19 pandemic and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero dollars per barrel for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. In 2021, U.S. oil production stabilized as commodity prices increased and demand for crude oil rebounded, which trend continued into 2022, with oil prices averaging $94.35 per barrel during that year. As a result, we saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services during 2022 and we expect both pricing and utilization to remain at these levels throughout 2023 as a result of an increase in budgets for publicly traded exploration and production companies and elevated activity levels, driven by improved energy demand and strong commodity prices. Concerns over potential recession or prolonged economic slowdown in the U.S. and globally and the ongoing Russian/Ukrainian war, however, could have an adverse impact on the global energy markets and volatility of commodity prices.

In the energy services industry, an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced and skilled workforce. Many of our larger customers place an emphasis not only on pricing, but also on safety records and quality management systems of contractors. We have committed resources toward employee safety and quality management training programs. Our field employees are required to complete both technical and safety training programs. Further, as part of our safety program and remediation procedures, we check treating iron for any defects on a periodic basis to avoid iron failure during hydraulic fracturing operations, marking such treating iron to reflect the most recent testing date. We also regularly monitor pressure levels in the treating iron used for fracturing and the surface casing to verify that the pressure and flow rates are consistent with the job specific model in an effort to avoid failure. As part of our safety procedures, we also have the capability to shut down our pressure pumping and fracturing operations both at the pumps and in our data van. In addition, we maintain spill kits on location for containment of pollutants that may be spilled in the process of providing our hydraulic fracturing services. The spill kits are generally comprised of pads and booms for absorption and containment of spills, as well as soda ash for neutralizing acid. Fire extinguishers are also in place on job sites at each pump.

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before commencing operations, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with our operations, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry and infrastructure industry in general. We have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA, or the “Superfund” law, and analogous state laws, generally imposes liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability, that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed substances (including substances disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers, which we refer to as the Corps. The scope of waters regulated under the CWA has fluctuated in recent years. On June 29, 2015, the EPA and the Corps jointly promulgated final rules expanding the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rules, and significantly reducing the waters subject to federal regulation under the Clean Water Act. On August 30, 2021, a federal court struck down the replacement rule and, on December 30, 2022, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015. Meanwhile, in October 2022, the Supreme Court heard oral arguments in a case addressing the proper test for determining whether wetlands are "waters of the United States". As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rules expand the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

A portion of our business is dependent on our ability to conduct hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals (also called “proppants”) under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plans. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities and the environmental impacts of discharges from CWT facilities. Furthermore, legislation to amend the Safe Drinking Water Act, or SDWA, to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress.

On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards, which we refer to as NSP standards, to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended the NSP standards to impose new standards for methane and VOC emissions for certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. However, on August 13, 2020, in response to an executive order by former President Trump to review and

revise unduly burdensome regulations, the EPA amended the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. On June 30, 2021, President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments (with the exception of some technical changes) thereby reinstating the 2012 and 2016 New Source Performance standards. The EPA expects owners and operators of regulated sources to take "immediate steps" to comply with these standards. Additionally, on November 15, 2021, the EPA published a proposed rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries and prohibiting venting of natural gas in certain situations. On December 6, 2022, the EPA published a supplemental proposal to strengthen the emission reduction requirements, which would, among other things, expand leak detection requirements and tighten flaring restrictions. These new standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

In addition, on March 26, 2015, the Bureau of Land Management, or BLM, published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. Also, on November 18, 2016, the BLM finalized a waste prevention rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. On March 28, 2017, the Trump Administration issued an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. A coalition of environmentalists, tribal advocates and the State of California filed lawsuits challenging the rule rescission. Also, on September 28, 2018, the BLM finalized revisions to the waste prevention rule to reduce “unnecessary compliance burdens”. However, a federal court struck down the scaled-back rule on July 15, 2020, and shortly thereafter, on October 8, 2020, another federal court struck down the 2016 waste prevention rule. On November 28, 2022, the BLM announced a proposed replacement rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and Indian lands, which would require the use of upgraded equipment in some cases and would place time and volume limits on royalty-free flaring. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations.

On October 19, 2017, one of our subsidiaries, Cobra, and PREPA entered into an emergency master services agreement for repairs to PREPA’s electrical grid as a result of Hurricane Maria. The one-year contract, as amended, provided for payments of up to $945 million (the “first contract”). On May 26, 2018, Cobra and PREPA entered into a second one-year, $900 million master services agreement to provide additional repair services and begin the initial phase of reconstruction of the electrical power system in Puerto Rico (the “second contract”). As of December 31, 2022, PREPA owed us approximately $227.0 million for services performed excluding $152.0 million of interest charged on these delinquent balances. PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under the contracts is largely dependent upon funding from the FEMA or other sources. On September 30, 2019, we filed a motion with the U.S. District Court for the District of Puerto Rico seeking recovery of the amounts owed to us by PREPA, which motion was stayed by the court. On March 25, 2020, we filed an urgent motion to modify the stay order and allow our recovery of approximately $62 million in claims related to a tax gross-up provision contained in the first contract. This emergency motion was denied on June 3, 2020 and the court extended the stay of our motion. On December 9, 2020, the Court again extended the stay of our motion and directed PREPA to file a status report by June 7, 2021. On April 6, 2021, we filed a motion to lift the stay order. Following this filing, PREPA initiated discussion with Cobra, which resulted in PREPA and Cobra filing a joint motion to adjourn all deadlines relative to the April 6, 2021 motion until the June 16, 2021 omnibus hearing as a result of PREPA’s understanding that FEMA would be releasing a report in the near future relating to the first contract. The joint motion was granted by the court on April 14, 2021. On May 26, 2021, FEMA issued a Determination Memorandum related to the first contract between Cobra and PREPA in which, among other things, FEMA raised two contract compliance issues and, as a result, concluded that approximately $47 million in costs were not authorized costs under the contract. On June 14, 2021, the Court issued an order adjourning Cobra’s motion to lift the stay order to a hearing on August 4, 2021 and directing Cobra and PREPA to meet and confer in good faith concerning, among other things, (i) the May 26, 2021 Determination Memorandum issued by FEMA and (ii) whether and when a second determination memorandum is expected. The parties were further directed to file an additional status report, which was filed on July 20, 2021. On July 23, 2021, with our aid, PREPA filed an appeal of the entire $47 million that FEMA de-obligated in the May 26, 2021 Determination Memorandum. FEMA approved the appeal in part and denied the appeal in part. FEMA found that staffing costs of $24.4 million are eligible for funding. On August 4, 2021, the Court denied Cobra’s April 6, 2021 motion to lift the stay order, extended the stay of our motion seeking recovery of amounts owed to Cobra and directed the parties to file an additional

joint status report, which was filed on January 22, 2022. On January 26, 2022, the Court extended the stay and directed the parties to file a further status report by July 25, 2022. On June 7, 2022, Cobra filed a motion to lift the stay order. On June 29, 2022 the Court denied Cobra’s motion and extended the stay to January 2023. On November 21, 2022, FEMA issued a Determination Memorandum related to the 100% federal funded portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $5.6 million in costs were not authorized costs under the contract. On December 21, 2022, FEMA issued a Determination Memorandum related to the 90% federal cost share portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $68.1 million in costs were not authorized costs under the contract. PREPA filed a first-level administrative appeal of the November 21, 2022 Determination Memorandum and has indicated that they will review the December 21, 2022 Determination Memorandum and, to the extent they feel plausible, file a first-level administrative appeal of the unauthorized amounts. On January 7, 2023, Cobra and PREPA filed a joint status report with the Court, in which PREPA requested that the Court continue the stay through July 31, 2023 and Cobra requested that the stay be lifted. On January 18, 2023, the Court entered an order extending the stay and directing the parties to file a further status report addressing (i) the status of any administrative appeals in connection with the November and December determination memorandums regarding the second contract, (ii) the status of the criminal proceeding against the former Cobra president and the FEMA official that concluded in December 2022, and (iii) a summary of the outstanding and unpaid amounts arising from the first and second contracts and whether PREPA disputes Cobra’s entitlement to these amounts with the Court by July 31, 2023. On January 20, 2023, Cobra submitted a certified claim for approximately $379 million to FEMA pursuant to the federal Contract Disputes Act. On February 1, 2023, FEMA notified Cobra that it had reviewed the claim and determined that no contract, expressed or implied, exists between FEMA and Cobra. Therefore, no final decision will be issued in response to Cobra’s claim. Cobra has 90 days from the February 1, 2023 decision to file a notice of appeal.

Our existing revolving credit facility is currently scheduled to mature on October 19, 2023. As of February 22, 2023, we had cash on hand of $9.5 million and outstanding borrowings under our revolving credit facility of $79.7 million, leaving an aggregate of $22.3 million of available borrowing capacity under this facility, after giving effect to $6.4 million of outstanding letters of credit and the requirement to maintain a $10.0 million reserve out of the available borrowing capacity. Our ability to extend, refinance or repay our existing revolving credit facility at or prior to maturity will depend on our ability to generate significant operating cash flow in the future and collect our receivables, among other factors. This ability is, to a significant extent, subject to general economic, financial, competitive and other factors, many of which are beyond our control. We cannot assure you that our business will generate cash flow from operations in amounts sufficient to enable us fund these and our other liquidity needs. As a result, we may need to seek additional debt or equity financing, sell existing assets or enter into other strategic transactions. We cannot assure you that we will be able to do so on commercially reasonable terms or at all, or on terms that would be advantageous to our stockholders. Considering the maturity date of our revolving credit facility, current macroeconomic conditions and recessionary pressures, we will likely be required to extend, refinance or repay our existing revolving credit facility in unfavorable credit markets. If we are unable to generate sufficient cash flow, complete any sale transactions, repay or refinance our indebtedness or incur additional indebtedness on commercially reasonable terms or at all, our financial condition will be adversely impacted. If we default under our existing revolving credit facility, the lenders could exercise their rights as described in this report under Note 10. Debt to our consolidated financial statements included elsewhere in this report, and we could be forced into bankruptcy or liquidation.

The COVID-19 pandemic has caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economy, including the global and domestic demand for oil and natural gas, which has had an adverse effect primarily on our oilfield services business and, as a result, our financial condition, results of operations, cash flows and stock price. There continues to be many variables and uncertainties regarding the COVID-19 pandemic, including the emergence, contagiousness and threat of new and different strains of the virus and their severity; the effectiveness of treatments or vaccines against the virus or its new strains; the extent of travel restrictions, business closures and other measures that are or may be imposed in affected areas or countries by governmental authorities; disruptions in the supply chain; an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic; shortages of equipment and materials; increased logistics costs; additional costs due to remote working arrangements; adherence to social distancing guidelines; and other COVID-19-related challenges. Further, there remain increased risks of cyberattacks on information technology systems used in remote or hybrid working environments; increased privacy-related risks due to processing health-related personal information; absence of workforce due to illness; the impact of the pandemic on any of our contractual counterparties; and other factors that are currently unknown or considered immaterial. It is difficult to assess the ultimate impact of the COVID-19 pandemic on our business, financial condition and cash flows.

filings that it may contend the alleged criminal activity affects Cobra's entitlement to payment under its contracts with PREPA. It is unclear what PREPA's position will be going forward. Subsequent to the indictment, we received (i) a preservation request letter from the SEC related to documents relevant to an ongoing investigation it is conducting and (ii) a civil investigative demand, or CID, from the United States Department of Justice, or DOJ, requesting certain documents and answers to interrogatories relevant to an ongoing investigation DOJ is conducting. Both the SEC and DOJ investigations relate to the same subjects as those at issue in the criminal matter referenced above. We are cooperating with the DOJ and are not able to predict the outcome of this investigation or if it will have a material impact on our business, financial condition, results of operations or cash flows. With regard to the SEC investigation, on July 6, 2022, the SEC sent a letter saying that it had concluded its investigation as to the Company and that based on information the SEC has as of this date, it does not intend to recommend an enforcement action by the SEC against us. Further, government contracts are subject to various uncertainties, restrictions and regulations, including oversight audits and compliance reviews by government agencies and representatives. Accordingly, it is possible that additional investigations may arise in the future.

Demand for our oil and natural gas products and services depends substantially on the level of capital expenditures by companies in the oil and natural gas industry. The levels of capital expenditures of our customers are predominantly driven by the prices of oil and natural gas. In March and April 2020, concurrent with the COVID-19 pandemic and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero dollars per barrel for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. Although commodity prices have strongly rebounded, with oil prices averaging $94.35 per barrel during 2022, they are expected to continue to be volatile as a result of production levels, inventories and demand, national and international economic performance and outlook. Other significant factors that are likely to continue to affect commodity prices in current and future periods include, but are not limited to, the effect of U.S. energy, monetary and trade policies, U.S. and global political developments, the impact and duration of the ongoing COVID-19 pandemic and conditions in the U.S. oil and gas industry, actions of OPEC+ members, the impact of the ongoing war in Ukraine on the global energy and capital markets and global stability and other factors. We anticipate demand for our oil and natural gas services and products will continue to be dependent on the level of capital expenditures by companies in the oil and natural gas industry and, ultimately, commodity prices. While we still expect commodity prices to be the primary driver of capital spending and industry activity levels in the future, other factors, such as debt repayment obligations and access to the capital markets, may play a significant role in the ultimate level of capital expenditures by the companies that use our completion and production, natural sand proppant and contract land and directional drilling service lines. Industry conditions are dynamic and the weakening of commodity prices from current levels may result in a material adverse impact on certain of our customers’ liquidity and financial position resulting in spending reductions, delays in the collection of amounts owing to us and similar impacts. These conditions, and others, have had and may continue to have an adverse impact on our financial condition, results of operations and cash flows, and it is difficult to predict how long the current commodity price environment will continue.

Under some of our infrastructure services contracts with customers, we provide a warranty for the services we provide, guaranteeing the work performed against defects in workmanship and material. As much of the work we perform is inspected by our customers for any defects in construction prior to acceptance of the project, we have not historically incurred warranty claims. Additionally, materials used in construction are often provided by the customer or are warranted against defects from the supplier. However, certain projects may have longer warranty periods and include facility performance warranties that may be broader than the warranties we generally provide. In these circumstances, if warranty claims occurred, it could require us to re-perform the services or to repair or replace the warranted item, at a cost to us, and could also result in other damages if we are not able to adequately satisfy our warranty obligations. In addition, we may be required under contractual arrangements with our customers to warrant any defects or failures in materials we provide that we purchase from third parties. While we generally require suppliers to provide us warranties that are consistent with those we provide to the customers, if any of these suppliers default on their warranty obligations to us, we may incur costs to repair or replace the defective materials for which we are not reimbursed. Costs incurred as a result of warranty claims could adversely affect our financial condition, results of operations and cash flows.

Our infrastructure services business involves professional judgments regarding the planning, design, development, construction, operations and management of electric power transmission and commercial construction. Because our projects are often technically complex, our failure to make judgments and recommendations in accordance with applicable professional standards, including engineering standards, could result in damages. While we do not generally accept liability for consequential damages, and although we have adopted a range of insurance, risk management and risk avoidance programs designed to reduce potential liabilities, a significantly adverse or catastrophic event at one of our project sites or completed projects resulting from the services we have performed could result in significant warranty, professional liability, or other claims against us as well as reputational harm, especially if public safety is impacted. These liabilities could exceed our insurance limits or could impact our ability to obtain insurance in the future. In addition, customers, subcontractors or suppliers who have agreed to indemnify us against any such liabilities or losses might refuse or be unable to pay us. An uninsured claim, either in part or in whole, if successful and of a material magnitude, could have a substantial impact on our business, financial condition, results of operations and cash flows.

As part of our natural sand proppant services business, we mine and process sand into premium monocrystalline sand, a specialized mineral that is used as a proppant (also known as frac sand) at our Barron County and Jackson County, Wisconsin plants. We sell natural sand proppant to our customers for use in their hydraulic fracturing operations to enhance the recovery rates of hydrocarbons from oil and natural gas wells. We also provide logistics solutions to deliver our frac sand products to our customers. Because our customers generally find it impractical to store frac sand in large quantities near their job sites, they seek to arrange for product to be delivered where and as needed, which requires predictable and efficient loading and shipping of product. To facilitate our logistics and transload facility capabilities, we contract with third party providers to transport our frac sand products to railroad facilities for delivery to our customers. We also lease a railcar fleet from various third parties to deliver our frac sand products to our customers and lease or otherwise utilize origin and destination transloading facilities. The suspension, termination or nonrenewal of our relationship with any one or more of these third parties involved in the sourcing, transportation and delivery of our frac sand products could result in material operational delays, increase our operating costs, limit our ability to service our customers’ wells or otherwise materially and adversely affect our business, financial condition, results of operations and cash flows.

In our natural sand proppant services business, we operate in a highly competitive market that is characterized by a small number of large, national producers and a larger number of small, regional or local producers. Competition in the industry is based on price, consistency and quality of product, site location, distribution and logistics capabilities, customer service, reliability of supply and breadth of product offering. The large, national producers with whom we compete include Badger Mining Corporation, Covia Holdings Corporation, Hi-Crush Partners LP, Capital Sand Proppants LLC, Athabasca Minerals Inc., Source Energy Services Ltd., and U.S. Silica Holdings Inc. Our larger competitors may have greater financial and other resources than we do, may develop technology superior to ours, may have production facilities that are located closer to sand mines from which raw sand is mined or to their key customers than our facilities or have a more cost effective access to raw sand and transportation facilities than we do. As the demand for hydraulic fracturing services has decreased due to commodity price volatility, prices in the frac sand market have materially decreased as demand for frac sand dropped and sand producers sought to preserve market share or exit the market and sell frac sand at below market prices. In addition, some oil and natural gas exploration and production companies and other providers of hydraulic fracturing services have acquired their own frac sand reserves, developed or expanded frac sand production capacity or otherwise fulfilled their own proppant requirements and existing or new frac sand producers could add to or expand their frac sand production capacity, which may negatively impact pricing and demand for our frac sand. We may not be able to compete successfully against either our larger or smaller competitors in the future, and competition could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In response to various factors, including fluctuations in oil and natural gas prices, our customers may shift their focus among resource plays, some of which can be located in geographic areas that do not have well-developed transportation and distribution infrastructure systems. Some geographic areas, including the areas in which our sand facilities are located, have limited access to railroads. Any interruption or delay in the railroad access or service may affect our ability to ship and/or the timing of shipment of our frac sand to our customers, which may adversely affect our revenues or result in increased costs, and thus could negatively impact our results of operations and financial condition. Serving our customers in these less-developed areas presents distribution and other operational challenges that may affect our sales and could negatively impact our operating costs. Labor disputes, system constraints, derailments, adverse weather conditions or other environmental events, an increasingly tight railcar leasing market and changes to rail freight systems, among other factors, could interrupt or limit available transportation services, could affect our ability to timely and cost-effectively deliver our frac sand to our customers and could provide a competitive advantage to our competitors located in closer proximity to our customers. Failure to find long-term solutions to these logistics challenges could adversely affect our business, financial condition, results of operations and cash flows.

The processing of raw sand and production of natural sand proppant require significant amounts of water. As a result, securing water rights and water access is necessary to operate our processing facilities. If the areas where our facilities are located experience water shortages, restrictions or any other constraints due to drought, contamination or otherwise, there may be additional costs associated with securing water access. Although we have obtained water rights to service our activities when we are operating our processing plants, the amount of water that we are entitled to use pursuant to our water rights must be determined by the appropriate regulatory authorities. Such regulatory authorities may amend the regulations regarding such water rights, increase the cost of maintaining such water rights or eliminate our current water rights, and we may be unable to retain all or a portion of such water rights. If implemented, these new regulations could also affect local municipalities and other industrial operations and could have a material adverse effect on costs involved in operating our processing plant. Such changes in laws, regulations or government policy and related interpretations pertaining to water rights may alter the environment in which we do business, which may have an adverse effect on our business, financial condition, results of operations and cash flows. Additionally, a water discharge permit may be required to properly dispose of water at our processing sites when in operation. Certain of our facilities are also required to obtain storm water permits. The water discharge, storm water or any other permits we may be required to have in order to conduct our frac sand processing operations is subject to regulatory discretion, and any inability to obtain or maintain the necessary permits could have an adverse effect on our ability to run such operations.

We provide food services to our customers as part of our remote accommodations business and, as a result, face health and food safety issues that are common in the food and hospitality industries. Food-borne illnesses, such as E. coli, hepatitis A, trichinosis or salmonella, and food safety issues have occurred in the food industry in the past and could occur in the future. Our reliance on third-party food suppliers and distributors increases the risk that food-borne illness incidents could be caused by factors outside of our control. New illnesses resistant to any precautions may develop in the future, or diseases with long incubation periods could arise. Further, the remote nature of our accommodation facilities and related food services may increase the risk of contamination of our food supply and create additional health and hygiene concerns due to the limited access to modern amenities and conveniences that may not be faced by other food service providers or hospitality businesses operating in an urban environment. If our customers become ill from food-borne illness, we could be forced to close some or all of our remote accommodation facilities on a temporary basis or otherwise. Any such incidents and/or any report of publicity linking us to incidents of food-borne illness or other food safety issues, including food tampering or contamination, could adversely affect our remote accommodations business as well as our overall financial condition and results of operations.

Claimants may seek large damage awards and defending claims can involve significant costs. When appropriate, we establish accruals for litigation and contingencies that we believe to be adequate in light of current information, legal advice and our indemnity insurance coverages. We reassess our potential liability for litigation and contingencies as additional information becomes available and adjust our accruals as necessary. We could experience a reduction in our profitability and liquidity if we do not properly estimate the amount of required accruals for litigation or contingencies, or if our insurance coverage proves to be inadequate or becomes unavailable, or if our self-insurance liabilities are higher than expected. The outcome of litigation is difficult to assess or quantify, as plaintiffs may seek recovery of very large or indeterminate amounts and the magnitude of the potential loss may remain unknown for substantial periods of time. Furthermore, because litigation is inherently uncertain, the ultimate resolution of any such claim, lawsuit or proceeding through settlement, mediation, or court judgment could have a material adverse effect on our business, financial condition or results of operations. In addition, claims, lawsuits and proceedings may harm our reputation or divert management’s attention from our business or divert resources away from operating our business, and cause us to incur significant expenses, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Please see Note 19. Commitments and Contingencies to our consolidated financial statements elsewhere in this annual report.

Our capital budget for 2023 is estimated to be $64 million, depending upon industry conditions and our financial results. We fund our capital expenditures primarily with cash generated by operations, borrowings under our revolving credit facility and sale-leaseback transactions. We may be unable to generate sufficient cash from operations and other capital resources to meet our operating needs and/or maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment, properly maintaining our existing equipment or restarting idled businesses or expanding existing operations as demand may warrant. Also, our existing revolving credit facility is currently scheduled to mature on October 19, 2023. Our ability to extend, refinance or repay our existing revolving credit facility at or prior to maturity will depend on our ability to generate significant operating cash flow in the future and collect our receivables, among other factors. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Revolving Credit Facility. Further, any disruptions or continuing volatility in the global financial markets and rising interest rates due to efforts to curb persistent inflation may lead to a contraction in credit availability and an increase in our cost of capital, which will adversely impact our ability to finance our operations. This could put us at a competitive disadvantage, impair our ability to meet our operating needs or interfere with our growth plans. Further,

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industries. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets. Our ability to grow through acquisitions and manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

The markets in which we operate are generally highly competitive and have relatively few barriers to entry. The principal competitive factors in our markets are price, product and service quality and availability, responsiveness, experience, technology, equipment quality and reputation for safety. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas or utility companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations include hazards inherent in the oil and natural gas and energy infrastructure industries, such as equipment defects, vehicle accidents, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards such as oil spills and releases of, and exposure to, hazardous substances. For example, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues. In addition, these risks may be greater for us than some of our competitors because we sometimes acquire companies that may not have allocated significant resources and management focus to safety and environmental matters and may have a poor environmental and safety record and associated possible exposure. Our insurance may not be adequate to cover all losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.

environmental liability, including leakage of hazardous substances from the wells to surface and subsurface soils, surface water or groundwater. We also handle, transport and store these substances. The handling, transportation, storage and disposal of these fluids are regulated by a number of laws, including: the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; and other federal and state laws and regulations promulgated thereunder. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. We could be exposed to liability for cleanup costs, natural resource damages and other damages under these and other environmental laws. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations have changed in the past, and they are likely to change in the future. If existing environmental requirements or enforcement policies change and become more stringent, we may be required to make significant unanticipated capital and operating expenditures. For a detailed description of environmental laws and regulations applicable to us and their impact on our operations, see “Item 1. Business—Regulations” above.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing-related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements related to underground injection activities. For example, the Oklahoma Corporations Commission has implemented a variety of measures, including the adoption of the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications and may restrict operations at existing wells. The Texas Railroad Commission has also implemented measures to assess the potential for seismic activity in the vicinity of disposal wells, and it has restricted and indefinitely suspended disposal well activities in some cases. These restrictions on the disposal of produced water and a moratorium on new produced water disposal wells could result in increased operating costs, requiring us to truck produced water, recycle it or dispose of it by other means, all of which could be costly and could adversely impact our results of operations, cash flows and liquidity.

In connection with our business operations, including the transportation and relocation of our energy service equipment, shipment of frac sand and general freight hauling, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials (HAZMAT). Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size. Interstate motor carrier operations are subject to safety requirements prescribed by the United States Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

We operate with most of our customers under master service agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

Our proppant sand reserves consist of Northern White silica sand, giving us access to a range of high-quality sand grades meeting or exceeding all API specifications, including a mix between concentrations of coarse grades (20/40 and 30/50 mesh sands) and finer grades (40/70 and 100 mesh). Our sample boring data and our historical production data have indicated that our reserves contain deposits of approximately 40% 40 mesh or coarser substrate. The coarseness and conductivity of Northern White frac sand significantly enhances recovery of oil and liquids-rich gas by allowing hydrocarbons to flow more freely than is sometimes possible with native sand. The low acid-solubility increases the integrity of Northern White frac sand relative to other proppants with higher acid-solubility, especially in shales where hydrogen sulfide and other acidic chemicals are co-mingled with the targeted hydrocarbons. In addition, its crush resistant properties enable Northern White frac sand to be used in deeper drilling applications than the frac sand produced from many native mineral deposits. We believe that the coarseness, conductivity, sphericity, acid-solubility and crush-resistant properties of our Northern White sand reserves and our facilities’ connectivity to rail and other transportation infrastructure afford us an advantage over our competitors and make us one of a select group of sand producers capable of delivering high volumes of frac sand that is optimal for oil and natural gas production to all major unconventional resource basins currently producing throughout North America.

We are an integrated, growth-oriented energy services company focused on providing products and services to enable the exploration and development of North American onshore unconventional oil and natural gas reserve as well as the construction and repair of the electric grid for private utilities, public investor-owned utilities and co-operative utilities through our infrastructure services businesses. Our primary business objective is to grow our operations and create value for stockholders through organic growth opportunities and accretive acquisitions. Our suite of services includes well completion services, infrastructure services, natural sand proppant services, drilling services and other services. Our well completion services division provides hydraulic fracturing, sand hauling and water transfer services. Our infrastructure services division provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells natural sand proppant used for hydraulic fracturing. Our drilling services division currently provides rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. In addition to these service divisions, we also provide aviation services, equipment rentals, crude oil hauling services, remote accommodations and equipment manufacturing. We believe that the services we offer play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources as well as in maintaining and improving electrical infrastructure. Our complementary suite of services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

allow our recovery of approximately $62 million in claims related to a tax gross-up provision contained in the first contract. This emergency motion was denied on June 3, 2020 and the Court extended the stay of our motion. On December 9, 2020, the Court again extended the stay of our motion and directed PREPA to file a status report by June 7, 2021. On April 6, 2021, we filed a motion to lift the stay order. Following this filing, PREPA initiated discussion with Cobra, which resulted in PREPA and Cobra filing a joint motion to adjourn all deadlines relative to the April 6, 2021 motion until the June 16, 2021 omnibus hearing as a result of PREPA’s understanding that FEMA would be releasing a report in the near future relating to the first contract. The joint motion was granted by the Court on April 14, 2021. On May 26, 2021, FEMA issued a Determination Memorandum related to the first contract between Cobra and PREPA in which, among other things, FEMA raised two contract compliance issues and, as a result, concluded that approximately $47 million in costs were not authorized costs under the contract. On June 14, 2021, the Court issued an order adjourning Cobra’s motion to lift the stay order to a hearing on August 4, 2021 and directing Cobra and PREPA to meet and confer in good faith concerning, among other things, (i) the May 26, 2021 Determination Memorandum issued by FEMA and (ii) whether and when a second determination memorandum is expected. The parties were further directed to file an additional status report, which was filed on July 20, 2021. On July 23, 2021, with our aid, PREPA filed an appeal of the entire $47 million that FEMA de-obligated in the May 26, 2021 Determination Memorandum. FEMA approved the appeal in part and denied the appeal in part. FEMA found that staffing costs of $24.4 million are eligible for funding. On August 4, 2021, the Court denied Cobra’s April 6, 2021 motion to lift the stay order, extended the stay of our motion seeking recovery of amounts owed to Cobra and directed the parties to file an additional joint status report, which was filed on January 22, 2022. On January 26, 2022, the Court extended the stay and directed the parties to file a further status report by July 25, 2022. On June 7, 2022, Cobra filed a motion to lift the stay order. On June 29, 2022 the Court denied Cobra’s motion and extended the stay to January 2023. On November 21, 2022, FEMA issued a Determination Memorandum related to the 100% federal funded portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $5.6 million in costs were not authorized costs under the contract. On December 21, 2022, FEMA issued a Determination Memorandum related to the 90% federal cost share portion of the second contract between Cobra and PREPA in which FEMA concluded that approximately $68.1 million in costs were not authorized costs under the contract. PREPA filed a first-level administrative appeal of the November 21, 2022 Determination Memorandum and has indicated that they will review the December 21, 2022 Determination Memorandums and, to the extent they feel plausible, file a first-level administrative appeal of the unauthorized amounts. On January 7, 2023, Cobra and PREPA filed a joint status report with the Court, in which PREPA requested that the Court continue the stay through July 31, 2023 and Cobra requested that the stay be lifted. On January 18, 2023, the Court entered an order extending the stay and directing the parties to file a further status report addressing (i) the status of any administrative appeals in connection with the November and December determination memorandums regarding the second contract, (ii) the status of the criminal proceedings against the former Cobra president and the FEMA official that concluded in December 2022, and (iii) a summary of the outstanding and unpaid amounts arising from the first and second contracts and whether PREPA disputes Cobra’s entitlement to these amounts with the Court by July 31, 2023. On January 20, 2023, Cobra submitted a certified claim for approximately $379 million to FEMA pursuant to the federal Contract Disputes Act. On February 1, 2023, FEMA notified Cobra that it had reviewed the claim and determined that no contract, expressed or implied, exists between FEMA and Cobra. Therefore, no final decision will be issued in response to Cobra’s claim. Cobra has 90 days from the February 1, 2023 decision to file a notice of appeal.

We believe all amounts charged to PREPA were in accordance with the terms of the contracts. Further, we believe these receivables are collectible. However, in the event PREPA (i) does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, (ii) obtains the necessary funds but refuses to pay the amounts owed to us or (iii) otherwise does not pay amounts owed to us for services performed, the receivable may not be collected and our financial condition, results of operations and cash flows would be materially and adversely affected. In addition, government contracts are subject to various uncertainties, restrictions and regulations, including oversight audits and compliance reviews by government agencies and representatives. In this regard, on September 10, 2019, the U.S. District Court for the District of Puerto Rico unsealed an indictment that charged the former president of Cobra with conspiracy, wire fraud, false statements and disaster fraud. Two other individuals were also charged in the indictment. The indictment was focused on the interactions between a former FEMA official and the former President of Cobra. Neither we nor any of our subsidiaries were charged in the indictment. On May 18, 2022, the former FEMA official and the former president of Cobra each pled guilty to one-count information charging gratuities related to a project that Cobra never bid upon and was never awarded or received any monies for. On December 13, 2022, the Court sentenced the former Cobra president to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and a fine of $25,000. The Court sentenced the FEMA official to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and a fine of $15,000. The Court also dismissed the indictment against the two defendants. We do not expect any additional activity in the criminal proceeding. Given the uncertainty inherent in the criminal litigation, however, it is not possible at this time to determine the potential impacts that the sentencings could have on us. PREPA has stated in Court filings that it may contend the alleged criminal activity affects Cobra's entitlement to payment under its contracts with PREPA. It is unclear what PREPA's position will be going forward. See Note 19. Commitments and Contingencies to our consolidated financial statements included elsewhere in this report for additional information regarding these investigations and proceedings. Further, as noted above, our

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021


	Years Ended
	December 31, 2022		December 31, 2021
Revenue:	(in thousands)
Well completion services	$	170,663	$	84,334
Infrastructure services	111,452		93,403
Natural sand proppant services	51,391		34,860
Drilling services	10,368		4,321
Other services	23,114		18,510
Eliminations	(4,902)		(6,466)
Total revenue	362,086		228,962

Cost of revenue:
Well completion services (exclusive of depreciation and amortization of $22,080 and $26,356, respectively, for 2022 and 2021)	128,742		64,552
Infrastructure services (exclusive of depreciation and amortization of $16,149 and $21,841, respectively, for 2022 and 2021)	91,649		90,559
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $8,725 and $8,993, respectively, for 2022 and 2021)	36,783		27,232
Drilling services (exclusive of depreciation and amortization of $6,466 and $7,995, respectively, for 2022 and 2021)	9,797		6,102
Other services (exclusive of depreciation and amortization of $10,850 and $13,209, respectively, for 2022 and 2021)	16,518		16,347
Eliminations	(4,902)		(6,466)
Total cost of revenue	278,587		198,326
Selling, general and administrative expenses	39,554		78,246
Depreciation, depletion, amortization and accretion	64,271		78,475
Gains on disposal of assets, net	(3,908)		(5,147)
Impairment of goodwill	—		891
Impairment of other long-lived assets	—		1,212
Operating loss	(16,418)		(123,041)
Interest expense, net	(11,506)		(6,406)
Other income, net	40,912		5,154
Income (loss) before income taxes	12,988		(124,293)
Provision (benefit) for income taxes	13,607		(22,863)
Net loss	$	(619)	$	(101,430)

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020


	Years Ended
	December 31, 2021		December 31, 2020
Revenue:	(in thousands)
Well completion services	$	84,334	$	88,325
Infrastructure services	93,403		157,751
Natural sand proppant services	34,860		34,360
Drilling services	4,321		7,785
Other services	18,510		28,829
Eliminations	(6,466)		(3,974)
Total revenue	228,962		313,076

Cost of Revenue:
Well completion services (exclusive of depreciation and amortization of $26,356 and $30,395, respectively, for 2021 and 2020)	64,552		47,483
Infrastructure services (exclusive of depreciation and amortization of $21,841 and $29,337, respectively, for 2021 and 2020)	90,559		124,555
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $8,993 and $9,758, respectively, for 2021 and 2020)	27,232		25,955
Drilling services (exclusive of depreciation and amortization of $7,995 and $10,036, respectively, for 2021 and 2020)	6,102		10,909
Other services (exclusive of depreciation and amortization of $13,209 and $15,713, respectively, for 2021 and 2020)	16,347		27,093
Eliminations	(6,466)		(3,974)
Total cost of revenue	198,326		232,021
Selling, general and administrative expenses	78,246		67,185
Depreciation, depletion, amortization and accretion	78,475		95,317
Gains on disposal of assets, net	(5,147)		(638)
Impairment of goodwill	891		54,973
Impairment of other long-lived assets	1,212		12,897
Operating loss	(123,041)		(148,679)
Interest expense, net	(6,406)		(5,397)
Other income, net	5,154		34,300
Loss before income taxes	(124,293)		(119,776)
Benefit for income taxes	(22,863)		(12,169)
Net loss	$	(101,430)	$	(107,607)

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net (loss) income before depreciation, depletion, amortization and accretion, gains on disposal of assets, net, impairment of goodwill, impairment of other long-lived assets, public offering costs, stock based compensation, interest expense, net, other income, net (which is comprised of interest on trade accounts receivable and certain legal expenses) and provision (benefit) for income taxes, further adjusted to add back interest on trade accounts receivable. We exclude the items listed above from net (loss) income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industries depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net (loss) income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The demand, pricing and terms for our products and services are largely dependent upon the level of activity for the U.S. oil and natural gas industry, energy infrastructure industry and natural sand proppant industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas services, energy infrastructure services and natural sand proppant; demand for repair and construction of transmission lines, substations and distribution networks in the energy infrastructure industry and the level of expenditures of utility companies; the level of prices of, and expectations about future prices for, oil and natural gas and natural sand proppant, as well as energy infrastructure services; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves and frac sand reserves meeting industry specifications and consisting of the mesh size in demand; access to pipeline, transloading and other transportation facilities and their capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers and other users of our services to raise equity capital and debt financing; and merger and divestiture activity in industries in which we operate.

In March and April 2020, concurrent with the COVID-19 pandemic and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero dollars per barrel for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. In 2021, U.S. oil production stabilized as commodity prices increased and demand for crude oil rebounded, many exploration and production companies set their operating budgets based on the prevailing prices for oil and natural gas at the time. Despite improvement in the U.S. and global economic activity, easing of the COVID-19 pandemic and related restrictions, rising energy use and improved commodity prices, the budgets for the publicly traded exploration and production companies remained relatively flat throughout 2021, with any excess cash flows used for debt repayment and shareholder returns, rather than to increase production. We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services throughout 2022 and we expect both pricing and utilization to continue at these levels throughout 2023 as a result of an increase in budgets for publicly traded exploration and production companies and elevated activity levels, driven by strong energy demand and favorable commodity prices. Strong demand in the pressure pumping industry and continuing supply chain disruptions have resulted, however, in delays of equipment and replacement parts for our and our competitors’ pressure pumping fleets. Further, the ongoing war and related humanitarian crisis in Ukraine could continue to have an adverse effect on the global supply chain and volatility of commodity prices.

As described further in Notes 2 and 19 to the consolidated financial statements, Cobra Acquisitions LLC (“Cobra”) and the Puerto Rico Electric Power Authority (“PREPA”) entered into an emergency master services agreement in October 2017 and a second master service contract in May 2018 for repairs to PREPA’s electrical grid due to damage caused by Hurricane Maria in 2017 (collectively, the “PREPA Contracts”). As of December 31, 2022, the consolidated financial statements include accounts receivable from PREPA for approximately $227.0 million for services performed as well as receivables of approximately $152.0 million of interest charges on delinquent balances in accordance with the terms of the PREPA Contracts (collectively, “PREPA receivable”). PREPA is subject to bankruptcy proceedings that are currently pending in the U.S. District Court for the District of Puerto Rico. Furthermore, on September 10, 2019, the U.S. District Court for the District of Puerto Rico unsealed an indictment that charged three individuals, including the former president of Cobra, with conspiracy, wire fraud, false statements and disaster fraud. The indictment was focused on the interactions between a former U.S. Department of Homeland Security - Federal Emergency Management Agency (“FEMA”) official and the former president of Cobra, which concluded in December 2022. The Company is cooperating with the U.S. Securities and Exchange Commission and the U.S. Department of Justice in the criminal matter and neither the Company nor any of its subsidiaries were charged in the indictment. However, adverse developments in the criminal investigation and/or related litigation may affect PREPA’s willingness or intent to remit payment to Cobra. We identified the collectability of the receivable balances associated with the PREPA Contracts as a critical audit matter.


ASSETS	December 31,
	2022		2021
CURRENT ASSETS	(in thousands)
Cash and cash equivalents	$	17,282	$	9,899
Short-term investment	—		1,762
Accounts receivable, net	456,465		407,550
Receivables from related parties, net	223		88
Inventories	8,883		8,366
Prepaid expenses	13,219		12,381
Other current assets	620		737
Total current assets	496,692		440,783

Property, plant and equipment, net	138,066		176,586
Sand reserves	61,830		64,641
Operating lease right-of-use assets	10,656		12,168
Intangible assets, net	1,782		2,561
Goodwill	11,717		11,717
Deferred income tax asset	—		8,094
Other non-current assets	3,935		4,342
Total assets	$	724,678	$	720,892

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	47,391	$	37,560
Accrued expenses and other current liabilities	52,297		62,516
Current operating lease liability	5,447		5,942
Current portion of long-term debt	83,520		1,468
Income taxes payable	48,557		42,748
Total current liabilities	237,212		150,234

Long-term debt, net of current portion	—		85,240
Deferred income tax liabilities	471		865
Long-term operating lease liability	4,913		5,918
Asset retirement obligations	3,981		3,720
Other long-term liabilities	15,485		11,693
Total liabilities	262,062		257,670

COMMITMENTS AND CONTINGENCIES (Note 19)

EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 47,312,270 and 46,684,065 issued and outstanding at December 31, 2022 and 2021	473		467
Additional paid in capital	539,138		538,221
Accumulated deficit	(73,154)		(72,535)
Accumulated other comprehensive loss	(3,841)		(2,931)
Total equity	462,616		463,222
Total liabilities and equity	$	724,678	$	720,892


	Years Ended December 31,
	2022		2021		2020
REVENUE	(in thousands, except per share amounts)
Services revenue	$	311,968	$	182,236	$	234,081
Services revenue - related parties	1,133		15,782		43,091
Product revenue	48,985		28,799		28,404
Product revenue - related parties	—		2,145		7,500
Total revenue	362,086		228,962		313,076

COST AND EXPENSES
Services cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $55,546, $69,401 and $85,481, respectively, for 2022, 2021, and 2020)	241,323		170,275		205,657
Services cost of revenue - related parties (exclusive of depreciation, depletion, amortization and accretion of $0, $0 and $0, respectively, for 2022, 2021, and 2020)	541		531		418
Product cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $8,725, $8,993 and $9,758, respectively, for 2022, 2021, and 2020)	36,723		27,520		25,946

Selling, general and administrative (Note 12)	39,554		77,861		66,427
Selling, general and administrative - related parties (Note 12)	—		385		758
Depreciation, depletion, amortization and accretion	64,271		78,475		95,317
Gains on disposal of assets, net	(3,908)		(5,147)		(638)
Impairment of goodwill	—		891		54,973
Impairment of other long-lived assets	—		1,212		12,897
Total cost and expenses	378,504		352,003		461,755
Operating loss	(16,418)		(123,041)		(148,679)

OTHER INCOME (EXPENSE)
Interest expense, net	(11,506)		(6,406)		(5,397)
Other income, net	40,912		5,669		32,410
Other (expense) income, net - related parties	—		(515)		1,890
Total other income (expense)	29,406		(1,252)		28,903
Income (loss) before income taxes	12,988		(124,293)		(119,776)
Provision (benefit) for income taxes	13,607		(22,863)		(12,169)
Net loss	$	(619)	$	(101,430)	$	(107,607)

OTHER COMPREHENSIVE LOSS
Foreign currency translation adjustment, net of tax of $0, ($36) and ($54), respectively, for 2022, 2021, and 2020	(910)		134		241
Comprehensive loss	$	(1,529)	$	(101,296)	$	(107,366)

Net loss per share (basic) (Note 15)	$	(0.01)	$	(2.18)	$	(2.36)
Net loss per share (diluted) (Note 15)	$	(0.01)	$	(2.18)	$	(2.36)
Weighted average number of shares outstanding (Note 15)	47,175		46,428		45,644
Weighted average number of shares outstanding, including dilutive effect (Note 15)	47,175		46,428		45,644


	Years Ended December 31,
	2022		2021		2020
Cash flows from operating activities	(in thousands)
Net loss	$	(619)	$	(101,430)	$	(107,607)
Adjustments to reconcile net loss to cash provided by (used in) operating activities:

Stock based compensation	923		1,191		1,952
Depreciation, depletion, amortization and accretion	64,271		78,475		95,317
Amortization of coil tubing strings	—		—		359
Amortization of debt origination costs	777		665		831
Bad debt expense (Note 2)	3,389		41,662		21,958
Gains on disposal of assets, net	(3,908)		(5,147)		(683)
Gains from sales of equipment damaged or lost down-hole	(604)		(288)		(696)
Impairment of goodwill	—		891		54,973
Impairment of other long-lived assets	—		1,212		12,897

Deferred income taxes	7,700		(32,005)		(12,186)
Other	(117)		280		(143)
Changes in assets and liabilities:
Accounts receivable, net	(52,392)		(55,898)		(32,621)
Receivables from related parties	(135)		28,373		(40,333)
Inventories	(517)		3,654		5,103
Prepaid expenses and other assets	(710)		1,444		1,996
Accounts payable	6,680		(2,982)		2,004
Accrued expenses and other liabilities	(15,272)		12,380		3,198
Income taxes payable	5,800		8,658		648
Net cash provided by (used in) operating activities	15,266		(18,865)		6,967

Cash flows from investing activities:
Purchases of property and equipment	(12,737)		(5,843)		(6,761)
Purchases of property and equipment from related parties	—		—		(76)

Contributions to equity investee	—		—		(490)
Proceeds from disposal of property and equipment	10,613		11,350		6,782
Purchase of short-term investment	—		—		(1,750)

Net cash (used in) provided by investing activities	(2,124)		5,507		(2,295)

Cash flows from financing activities:
Borrowings on long-term debt	197,975		73,100		35,351
Repayments of long-term debt	(199,430)		(68,911)		(32,800)
Proceeds from sale-leaseback transaction	4,589		9,473		5,000
Payments on sale-leaseback transaction	(4,429)		(2,951)		(268)

Principal payments on financing leases and equipment financing notes	(4,306)		(2,283)		(1,966)
Debt issuance costs	—		—		(1,051)
Net cash (used in) provided by financing activities	(5,601)		8,428		4,266
Effect of foreign exchange rate on cash	(158)		7		12
Net increase (decrease) in cash and cash equivalents	7,383		(4,923)		8,950
Cash and cash equivalents at beginning of period	9,899		14,822		5,872
Cash and cash equivalents at end of period	$	17,282	$	9,899	$	14,822


Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☒
		Emerging growth company	☐




		Page
	Glossary of Oil and Natural Gas and Electrical Infrastructure Terms	i
	Cautionary Note Regarding Forward-Looking Statements	iv

PART I.		1
Item 1.	Business	1
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	44
Item 2.	Properties	44
Item 3.	Legal Proceedings	51
Item 4.	Mine Safety Disclosure	52

PART II.		53
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	53
Item 6.	[Reserved]	53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	78
Item 8.	Financial Statements and Supplementary Data	79
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	79
Item 9A.	Controls and Procedures	79
Item 9B.	Other Information	80
Item 9C.	Disclosure Regarding Foreign Jurisdictions the Prevent Inspections	80

PART III.		81
Item 10.	Directors, Executive Officers and Corporate Governance	81
Item 11.	Executive Compensation	81
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	81
Item 13.	Certain Relationships and Related Transactions and Director Independence	81
Item 14.	Principal Accountant Fees and Services	81

PART IV.		82
Item 15.	Exhibits and Financial Statement Schedules	82
Item 16.	Form 10-K Summary	83

SIGNATURES		84


The following is a glossary of certain electrical infrastructure industry terms used in this report:
Distribution			The distribution of electricity from the transmission system to individual customers.
Substation			A part of an electrical transmission and distribution system that transforms voltage from high to low, or the reverse.
Transmission			The movement of electrical energy from a generating site, such as a power plant, to an electric substation.


	Total Sand Mined (Thousands of Tons)
	As of December 31,
	2022	2021	2020
Plant Location
Taylor in Jackson County, Wisconsin	630	567	589
Piranha in Barron County, Wisconsin	766	320	—

Total	1,396	887	589


Mine	Reserves Category	Total Reserves(1)(2)
Taylor	Proven	23,822
Piranha	Proven	37,351
Total		61,173


☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


	Amount as of
Reserves Category	December 31, 2022	December 31, 2021	Change	% Change
Proven	23,822	24,277	(455)	(2)	%


	Years Ended December 31,
Reconciliation of Adjusted EBITDA to net loss:	2022		2021		2020
Net loss	$	(619)	$	(101,430)	$	(107,607)
Depreciation, depletion, amortization and accretion	64,271		78,475		95,317
Gains on disposal of assets, net	(3,908)		(5,147)		(638)
Impairment of goodwill	—		891		54,973
Impairment of other long-lived assets	—		1,212		12,897


Public offering costs	—		91		—

Stock based compensation	923		1,191		1,952
Interest expense, net	11,506		6,406		5,397
Other income, net	(40,912)		(5,154)		(34,300)
Provision (benefit) for income taxes	13,607		(22,863)		(12,169)
Interest on trade accounts receivable	41,276		34,709		34,130
Adjusted EBITDA	$	86,144	$	(11,619)	$	49,952


	Total		Less than 1 year		1-3 Years		3-5 Years		More than 5 Years
Contractual obligations:
Revolving credit facility(a)	$	83,520	$	83,520	$	—	$	—	$	—
Interest and commitment fees on revolving credit facility(b)	7,843		7,843		—		—		—
Sale-leaseback arrangements(c)	10,502		5,675		4,827		—		—
Operating lease obligations(d)	11,019		5,719		4,742		160		398
Financing lease obligations(e)	6,842		4,148		1,899		795		—
Equipment financing obligations(f)	10,719		3,390		6,765		564		—


	$	130,445	$	110,295	$	18,233	$	1,519	$	398


		Page
Financial Statements
	Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)	1
	Consolidated Balance Sheets	3
	Consolidated Statement of Comprehensive Loss	4
	Consolidated Statement of Changes in Equity	5
	Consolidated Statement of Cash Flows	6
	Notes to Consolidated Financial Statements	8


Exhibit Number									Exhibit Description
3.1									Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on November 15, 2016).
3.2									Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on November 15, 2016).
4.1									Description of Securities of the Company (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K (File No. 001-37917), filed with the SEC on March 2, 2020).
4.2									Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company’s Amendment No. 2 to the Registration Statement on Form S-1/A (File No. 333-213504), filed with the SEC on October 3, 2016).
4.3									Registration Rights Agreement, dated October 12, 2016, by and between the Company and Mammoth Energy Holdings, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on November 15, 2016).
10.1									Advisory Services Agreement, dated as of October 19, 2016, by and between the Company and Wexford Capital LP (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on November 15, 2016).
10.2									Mammoth Energy Securities, Inc. 2016 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on November 15, 2016).
10.3									Form of Option Agreement (incorporated by reference to Exhibit 10.12 to the Company’s Amendment No. 1 to the Registration Statement on Form S-1/A (File No. 333-213504), filed with the SEC on September 23, 2016).
10.4									Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.13 to the Company’s Amendment No. 1 to the Registration Statement on Form S-1/A (File No. 333-213504), filed with the SEC on September 23, 2016).
10.5†									Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.14 to the Company’s Amendment No. 2 to the Registration Statement on Form S-1/A (File No. 333-213504), filed with the SEC on October 3, 2016).
10.6									Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, executed on October 19, 2017, by the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (File No. 001-37917), filed with the SEC on November 14, 2017).
10.7									Amendment No. 1 to Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, executed on November 1, 2017, by the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q (File No. 001-37917), filed with the SEC on November 14, 2017).
10.8									Amendment No. 2 to Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, dated as of December 8, 2017, between the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on January 31, 2018).
10.9									Amendment No. 3 to Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, dated December 21, 2017, between the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on January 31, 2018).
10.10									Amendment No. 4 to Emergency Master Service Agreement for PREPA’s Electrical Grid Repairs-Hurricane Maria, dated as of January 28, 2018, between the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (File No. 001-37917), filed with the SEC on January 31, 2018).
10.1 1									Amendment No. 5 to Emergency Master Service Agreement for PREPA's Electrical Grid Repairs-Hurricane Maria, dated as of February 27, 2018, between the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC (incorporated by reference to Exhibit 10.34 to the Company's Annual Report on Form 10-K (File No. 001-37917), filed with the SEC on February 28, 2018).


Signature	Title	Date

/s/ Arty Straehla	Chief Executive Officer (principal executive officer) and Director	February 24, 2023
Arty Straehla

/s/ Mark Layton	Chief Financial Officer (principal financial and accounting officer)	February 24, 2023
Mark Layton

/s/ Arthur Amron	Director (Chairman of the Board)	February 24, 2023
Arthur Amron

/s/ James D. Palm	Director	February 24, 2023
James D. Palm

/s/ Paul Jacobi	Director	February 24, 2023
Paul Jacobi

/s/ Arthur Smith	Director	February 24, 2023
Arthur Smith

/s/ Corey Booker	Director	February 24, 2023
Corey Booker


								Accumulated
						Additional		Other
	Common Stock			Retained		Paid-In		Comprehensive
	Shares	Amount		Earnings (Deficit)		Capital		Loss		Total
	(in thousands)
Balance at January 1, 2020	45,109	$	451	$	136,502	$	535,094	$	(3,306)	$	668,741
Stock based compensation	660	7		—		1,945		—		1,952
Net loss	—	—		(107,607)		—		—		(107,607)

Other comprehensive income	—	—		—		—		241		241
Balance at December 31, 2020	45,769	$	458	$	28,895	$	537,039	$	(3,065)	$	563,327
Stock based compensation	915	9		—		1,182		—		1,191
Net loss	—	—		(101,430)		—		—		(101,430)

Other comprehensive income	—	—		—		—		134		134
Balance at December 31, 2021	46,684	$	467	$	(72,535)	$	538,221	$	(2,931)	$	463,222
Stock based compensation	628	6		—		917		—		923
Net loss	—	—		(619)		—		—		(619)

Other comprehensive loss	—	—		—		—		(910)		(910)
Balance at December 31, 2022	47,312	$	473	$	(73,154)	$	539,138	$	(3,841)	$	462,616


Balance, January 1, 2020	$	5,154
Additions charged to bad debt expense	22,705
Additions charged to other selling, general and administrative expense	3,950
Additions charged to other, net - related parties	1,427
Recoveries of receivables previously charged to bad debt expense	(747)
Deductions for uncollectible receivables written off	(2,350)
Balance, December 31, 2020	30,139
Additions charged to bad debt expense	41,873
Additions charged to revenue	27,071
Additions charged to other selling, general and administrative expense	273
Additions charged to other, net - related parties	515
Additions charged to other income (expense), net	1,474
Recoveries of receivables previously charged to bad debt expense	(211)
Deductions for uncollectible receivables written off	(83,049)
Balance, December 31, 2021	18,085
Additions charged to bad debt expense	3,550
Recoveries of receivables previously charged to bad debt expense	(161)
Deductions for uncollectible receivables written off	(17,887)
Balance, December 31, 2022	$	3,587


	Years Ended December 31,
	2022		2021		2020
Well completion services(a)	$	11,421	$	4,327	$	4,358
Infrastructure services(b)	885		627		258
Natural sand proppant services(c)	88		484		1,073
Drilling services(d)	101		44		432
Other(e)	395		361		716
Eliminations	(153)		—		—
Total capital expenditures	$	12,737	$	5,843	$	6,837


Balance, January 1, 2021	22,581
Additions charged to bad debt expense	41,196
Additions charged to revenue	27,070
Additions charged to other income (expense), net - related parties	1,842
Deductions for uncollectible receivables written off	(80,975)
Balance, December 31, 2021	11,714
Recoveries of receivables previously charged to bad debt expense	(147)
Deductions for uncollectible receivables written off	(11,567)
Balance, December 31, 2022	$	—


	REVENUES						ACCOUNTS RECEIVABLE
	Years Ended December 31,						At December 31,
	2022		2021		2020		2022		2021
Customer A(a)	10	%	6	%	—	%	—	%	—	%
Customer B(b)	—	%	—	%	—	%	83	%	83	%
Customer C(c)	—	%	7	%	16	%	—	%	—	%
Customer D(d)	—	%	3	%	15	%	—	%	—	%


Balance, January 1, 2020	$	7,244
Deduction for recognition of revenue	(25,047)
Increase for deferral of shortfall payments	25,436
Increase for deferral of customer prepayments	648

Balance, December 31, 2020	8,281
Deduction for recognition of revenue	(12,329)
Increase for deferral of shortfall payments	7,023
Increase for deferral of customer prepayments	275

Balance, December 31, 2021	3,250
Deduction for recognition of revenue	(3,207)
Deduction for rebate credit recognized	(140)
Increase for deferral of customer prepayments	7,647
Balance, December 31, 2022	$	7,550


		December 31,
	Useful Life	2022		2021
Pressure pumping equipment	3-5 years	$	230,760	$	220,414
Drilling rigs and related equipment	3-15 years	110,724		111,478
Machinery and equipment	7-20 years	162,634		166,873
Buildings(a)	15-39 years	40,316		46,006
Vehicles, trucks and trailers	5-10 years	101,580		103,982
Coil tubing equipment	4-10 years	6,908		7,592
Land	N/A	12,393		13,417
Land improvements	15 years or life of lease	10,053		10,133
Rail improvements	10-20 years	13,793		13,793
Other property and equipment(b)	3-12 years	18,296		18,235
		707,457		711,923
Deposits on equipment and equipment in process of assembly(c)		13,885		3,300
		721,342		715,223
Less: accumulated depreciation(d)		583,276		538,637
Total property, plant and equipment, net		$	138,066	$	176,586


	Infrastructure		Well Completion		Sand		Other		Total
Balance as of January 1, 2021
Goodwill	$	891	$	86,043	$	2,684	$	14,830	$	104,448
Accumulated impairment losses	—		(76,829)		(2,684)		(12,327)		(91,840)
	891		9,214		—		2,503		12,608
Acquisitions	—		—		—		—		—
Impairment losses(a)	(891)		—		—		—		(891)
Balance as of December 31, 2021
Goodwill	891		86,043		2,684		14,830		104,448
Accumulated impairment losses	(891)		(76,829)		(2,684)		(12,327)		(92,731)
	—		9,214		—		2,503		11,717
Acquisitions	—		—		—		—		—
Impairment losses	—		—		—		—		—
Balance as of December 31, 2022
Goodwill	891		86,043		2,684		14,830		104,448
Accumulated impairment losses	(891)		(76,829)		(2,684)		(12,327)		(92,731)
	$	—	$	9,214	$	—	$	2,503	$	11,717


Year ended December 31:	Amount
2023	$	779
2024	710
2025	91
2026	91
2027	45
Thereafter	66
	$	1,782


	Year Ended December 31,
	2022		2021		2020
U.S. current income tax expense (benefit)	$	61	$	290	$	(6,931)
U.S. deferred income tax benefit	(207)		(23,740)		(12,330)
Foreign current income tax expense	5,846		8,852		6,948
Foreign deferred income tax expense (benefit)	7,907		(8,265)		144
Total	$	13,607	$	(22,863)	$	(12,169)


	Operating Leases		Finance Leases
2023	$	5,731	$	4,148
2024	3,708		1,203
2025	1,034		696
2026	147		795
2027	12		—
Thereafter	399		—
Total lease payments	11,031		6,842
Less: Present value discount	671		237
Present value of lease payments	$	10,360	$	6,605


	Number of Unvested Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested restricted stock units as of January 1, 2020	221,241	$	22.43
Granted	2,401,446	0.98
Vested	(660,738)	5.32
Forfeited	(47,167)	3.28
Unvested restricted stock units as of December 31, 2020	1,914,782	1.21
Granted	128,205	3.90
Vested	(914,782)	1.52
Forfeited	—	—
Unvested restricted stock units as of December 31, 2021	1,128,205	1.27
Granted	228,310	2.19
Vested	(628,205)	1.54
Forfeited	—	—
Unvested restricted stock units as of December 31, 2022	728,310	1.32


		COST OF REVENUE						ACCOUNTS PAYABLE
		Years Ended December 31,						At December 31,
		2022		2021		2020		2022		2021
Cobra Aviation/ARS/Leopard and Brim Equipment	(a)	77		73		72		3		5
The Company and Caliber	(b)	357		351		248		—		—
Other Relationships		107		107		98		—		—
		$	541	$	531	$	418	$	3	$	5

		SELLING, GENERAL AND ADMINISTRATIVE COSTS
The Company and Wexford	(c)	—		5		3		—		—
The Company and Caliber	(b)	—		374		774		—		—
Other Relationships		—		8		(19)		—		—
		$	—	$	387	$	758	$	—	$	—




								$	3	$	5


Year Ended December 31, 2022	Well Completion		Infrastructure		Sand		Drilling		All Other		Eliminations		Total
Revenue from external customers	$	169,872	$	111,452	$	48,916	$	10,346	$	21,500	$	—	$	362,086
Intersegment revenues	791		—		2,475		22		1,614		(4,902)		—
Total revenue	170,663		111,452		51,391		10,368		23,114		(4,902)		362,086
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	124,848		91,577		36,783		9,259		16,120		—		278,587
Intersegment cost of revenues	3,894		72		—		538		398		(4,902)		—
Total cost of revenue	128,742		91,649		36,783		9,797		16,518		(4,902)		278,587
Selling, general and administrative	8,642		19,147		7,171		1,241		3,353		—		39,554
Depreciation, depletion, amortization and accretion	22,103		16,171		8,732		6,467		10,798		—		64,271
Gains on disposal of assets, net	(615)		(795)		(89)		(172)		(2,237)		—		(3,908)


Operating (loss) income	11,791		(14,720)		(1,206)		(6,965)		(5,318)		—		(16,418)
Interest expense	1,940		7,390		753		545		878		—		11,506
Other income, net	(343)		(40,470)		(14)		—		(85)		—		(40,912)
Income (loss) before income taxes	$	10,194	$	18,360	$	(1,945)	$	(7,510)	$	(6,111)	$	—	$	12,988
Total expenditures for property, plant and equipment	$	11,421	$	885	$	88	$	101	$	395	$	(153)	$	12,737
As of December 31, 2022:
Intangible assets, net	$	1,307	$	135	$	—	$	—	$	340	$	—	$	1,782
Total assets	$	82,897	$	450,841	$	129,467	$	21,755	$	120,164	$	(80,446)	$	724,678


Year Ended December 31, 2021	Well Completion		Infrastructure		Sand		Drilling		All Other		Eliminations		Total
Revenue from external customers	$	84,190	$	93,403	$	30,880	$	4,197	$	16,292	$	—	$	228,962
Intersegment revenue	144		—		3,980		124		2,218		(6,466)		—
Total revenue	84,334		93,403		34,860		4,321		18,510		(6,466)		228,962
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	58,782		90,363		27,232		6,102		15,847		—		198,326
Intersegment cost of revenues	5,770		196		—		—		500		(6,466)		—
Total cost of revenue	64,552		90,559		27,232		6,102		16,347		(6,466)		198,326
Selling, general and administrative	49,275		18,267		5,351		1,414		3,939		—		78,246
Depreciation, depletion, amortization and accretion	26,377		21,880		9,005		7,996		13,217		—		78,475
Gains on disposal of assets, net	(770)		(286)		(30)		(202)		(3,859)		—		(5,147)
Impairment of goodwill	—		891		—		—		—		—		891
Impairment of other long-lived assets	—		665		—		—		547		—		1,212
Operating loss	(55,100)		(38,573)		(6,698)		(10,989)		(11,681)		—		(123,041)
Interest expense	1,107		3,925		474		293		607		—		6,406
Other (income) expense, net	1,843		(6,499)		(844)		25		321		—		(5,154)
Loss before income taxes	$	(58,050)	$	(35,999)	$	(6,328)	$	(11,307)	$	(12,609)	$	—	$	(124,293)
Total expenditures for property, plant and equipment	$	4,327	$	627	$	484	$	44	$	361	$	—	$	5,843
As of December 31, 2021:
Intangible assets, net	$	1,995	$	165	$	—	$	—	$	401	$	—	$	2,561
Total assets	$	56,036	$	427,626	$	156,519	$	27,457	$	129,202	$	(75,948)	$	720,892


Year Ended December 31, 2020	Well Completion		Infrastructure		Sand		Drilling		All Other		Eliminations		Total
Revenue from external customers	$	87,201	$	157,751	$	34,265	$	7,746	$	26,113	$	—	$	313,076
Intersegment revenues	1,124		—		95		39		2,716		(3,974)		—
Total revenue	88,325		157,751		34,360		7,785		28,829		(3,974)		313,076
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	45,647		124,232		25,955		10,757		25,430		—		232,021
Intersegment cost of revenues	1,836		323		—		152		1,663		(3,974)		—
Total cost of revenue	47,483		124,555		25,955		10,909		27,093		(3,974)		232,021
Selling, general and administrative	23,039		27,261		7,807		3,149		5,929		—		67,185
Depreciation, depletion, amortization and accretion	30,411		29,373		9,771		10,039		15,723		—		95,317
(Gains) losses on disposal of assets, net	(388)		(444)		1,829		(352)		(1,283)		—		(638)
Impairment of goodwill	53,406		—		—		—		1,567		—		54,973
Impairment of other long-lived assets	4,203		—		—		326		8,368		—		12,897
Operating loss	(69,829)		(22,994)		(11,002)		(16,286)		(28,568)		—		(148,679)
Interest expense	1,130		2,794		312		454		707		—		5,397
Other expense, net	(1,886)		(31,993)		10		125		(556)		—		(34,300)
Income (loss) before income taxes	$	(69,073)	$	6,205	$	(11,324)	$	(16,865)	$	(28,719)	$	—	$	(119,776)
Total expenditures for property, plant and equipment	$	4,358	$	258	$	1,073	$	432	$	716	$	—	6,837
As of December 31, 2020:
Intangible assets, net	$	2,683	$	1,063	$	—	$	—	$	1,028	$	—	$	4,774
Total assets	$	99,247	$	437,296	$	172,927	$	36,252	$	136,422	$	(57,582)	$	824,562


Name of Subsidiary
5 Star Electric LLC
Air Rescue Systems Corporation
Anaconda Manufacturing LLC
Anaconda Rentals LLC
Aquahawk Energy LLC
Aquawolf LLC
Barracuda Logistics LLC
Bison Drilling and Field Services LLC
Bison Sand Logistics LLC
Bison Trucking LLC
Black Mamba Energy 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
Ivory Freight Solutions LLC
Leopard Aviation LLC
Mako Acquisitions LLC
Mammoth Energy Partners LLC
Mammoth Equipment Leasing LLC
Mr. Inspections LLC
Muskie Proppant LLC
Panther Drilling Systems LLC
Piranha Proppant LLC
Predator Aviation LLC
Python Equipment LLC
Redback Coil Tubing LLC
Redback Energy Services LLC
Redback Pumpdown Services LLC
Stingray Cementing and Acidizing LLC
Silverback Energy LLC
South River Road LLC
Stingray Cementing LLC
Stingray Energy Services LLC
Stingray Pressure Pumping LLC
Sturgeon Acquisitions LLC
Taylor Frac LLC
Taylor Real Estate Investments LLC
Tiger Shark Logistics LLC
WTL Oil LLC


									MAMMOTH ENERGY SERVICES, INC.
			By:						/s/ Arty Straehla
									Arty Straehla
									Chief Executive Officer
									February 24, 2023

Cover Page - USD ($) $ in Millions	12 Months Ended
Cover Page - USD ($) $ in Millions	Dec. 31, 2022	Feb. 22, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-37917
Entity Registrant Name	Mammoth Energy Services, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	32-0498321
Entity Address, Address Line One	14201 Caliber Drive,
Entity Address, Address Line Two	Suite 300
Entity Address, City or Town	Oklahoma City,
Entity Address, State or Province	OK
City Area Code	(405)
Local Phone Number	608-6007
Entity Address, Postal Zip Code	73134
Title of 12(b) Security	Common Stock
Trading Symbol	TUSK
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float			$ 50.9
Entity Common Stock, Shares Outstanding		47,312,270
Documents Incorporated by Reference	DOCUMENTS INCORPORATION BY REFERENCE Portions of Mammoth Energy Services, Inc.’s Proxy Statement for the 2023 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
Entity Central Index Key	0001679268
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2022
Auditor Information [Abstract]
Auditor Firm ID	248
Auditor Name	GRANT THORNTON LLP
Auditor Location	Oklahoma City, Oklahoma

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
CURRENT ASSETS
Cash and cash equivalents	$ 17,282	$ 9,899
Short-term investment	0	1,762
Accounts receivable, net	456,465	407,550
Receivables from related parties, net	223	88
Inventories	8,883	8,366
Prepaid expenses	13,219	12,381
Other current assets	620	737
Total current assets	496,692	440,783
Property, plant and equipment, net	138,066	176,586
Sand reserves	61,830	64,641
Operating lease right-of-use assets	10,656	12,168
Intangible assets, net	1,782	2,561
Goodwill	11,717	11,717
Deferred income tax asset	0	8,094
Other non-current assets	3,935	4,342
Total assets	724,678	720,892
CURRENT LIABILITIES
Accounts payable	47,391	37,560
Accrued expenses and other current liabilities	52,297	62,516
Current operating lease liability	5,447	5,942
Current portion of long-term debt	83,520	1,468
Income taxes payable	48,557	42,748
Total current liabilities	237,212	150,234
Long-term debt, net of current portion	0	85,240
Deferred income tax liabilities	471	865
Long-term operating lease liability	4,913	5,918
Asset retirement obligations	3,981	3,720
Other long-term liabilities	15,485	11,693
Total liabilities	262,062	257,670
COMMITMENTS AND CONTINGENCIES (Note 19)
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 47,312,270 and 46,684,065 issued and outstanding at December 31, 2022 and 2021	473	467
Additional paid in capital	539,138	538,221
Accumulated deficit	(73,154)	(72,535)
Accumulated other comprehensive loss	(3,841)	(2,931)
Total equity	462,616	463,222
Total liabilities and equity	$ 724,678	$ 720,892

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Common stock, par value (in USD per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	200,000,000	200,000,000
Common stock, shares, issued (in shares)	47,312,270	46,684,065
Common stock, shares, outstanding (in shares)	47,312,270	46,684,065

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
COST AND EXPENSES
Selling, general and administrative (Note 12)	$ 39,554	$ 77,861	$ 66,427
Selling, general and administrative - related parties (Note 12)	0	385	758
Depreciation, depletion, amortization and accretion	64,271	78,475	95,317
Gains on disposal of assets, net	(3,908)	(5,147)	(638)
Impairment of goodwill	0	891	54,973
Impairment of other long-lived assets	0	1,212	12,897
Operating loss	(16,418)	(123,041)	(148,679)
OTHER INCOME (EXPENSE)
Interest expense, net	(11,506)	(6,406)	(5,397)
Other income, net	40,912	5,669	32,410
Other (expense) income, net - related parties	0	(515)	1,890
Total other income (expense)	29,406	(1,252)	28,903
Income (loss) before income taxes	12,988	(124,293)	(119,776)
Provision (benefit) for income taxes	13,607	(22,863)	(12,169)
Net (loss) income	(619)	(101,430)	(107,607)
OTHER COMPREHENSIVE LOSS
Foreign currency translation adjustment, net of tax of $0, ($36) and ($54), respectively, for 2022, 2021, and 2020	(910)	134	241
Comprehensive loss	$ (1,529)	$ (101,296)	$ (107,366)
Net loss per share (basic) (in USD per share)	$ (0.01)	$ (2.18)	$ (2.36)
Net loss per share (diluted) (in USD per share)	$ (0.01)	$ (2.18)	$ (2.36)
Weighted average number of shares outstanding (in shares)	47,175	46,428	45,644
Weighted average number of shares outstanding, including dilutive effect (in shares)	47,175	46,428	45,644
Product And Service Including Related Party
REVENUE
Revenue	$ 362,086	$ 228,962	$ 313,076
COST AND EXPENSES
Total cost and expenses	378,504	352,003	461,755
Service
REVENUE
Revenue	311,968	182,236	234,081
COST AND EXPENSES
Cost of revenue	241,323	170,275	205,657
Product
REVENUE
Revenue	48,985	28,799	28,404
COST AND EXPENSES
Cost of revenue	36,723	27,520	25,946
Related parties
COST AND EXPENSES
Selling, general and administrative - related parties (Note 12)	0	387	758
Related parties \| Service
REVENUE
Revenue	1,133	15,782	43,091
COST AND EXPENSES
Cost of revenue	541	531	418
Related parties \| Product
REVENUE
Revenue	$ 0	$ 2,145	$ 7,500