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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2023
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 001-37917
 Mammoth Energy Services, Inc.
(Exact name of registrant as specified in its charter)
Delaware 32-0498321
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)
   
14201 Caliber Drive,Suite 300
Oklahoma City,Oklahoma(405)608-600773134
(Address of principal executive offices) (Registrant’s telephone number, including area code)(Zip Code)
Securities registered pursuant to Section 12(b) of The Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common StockTUSKThe Nasdaq Stock Market LLC
NASDAQ Global Select Market
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes      No  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes      No 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerAccelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  

The aggregate market value of common equity held by non-affiliates of the registrant as of June 30, 2023 was approximately $112.4 million, calculated based on the closing price of the common stock on the Nasdaq Global Select Market on that date.    

As of February 28, 2024, there were 47,941,652 shares of our $0.01 par value common stock outstanding.

DOCUMENTS INCORPORATION BY REFERENCE

Portions of Mammoth Energy Services, Inc.’s Proxy Statement for the 2024 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.



TABLE OF CONTENTS
 
  Page
Item 1.
Item 1A.
Item 1B.
Item 1C.
Item 2.
Item 3.
Item 4.
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
 




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”):
AcidizingTo pump acid into a wellbore to improve well productivity or injectivity.
BlowoutAn 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 assemblyThe 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.
CementingTo prepare and pump cement into place in a wellbore.
Coiled tubingA 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.
CompletionA 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 drillingThe 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-holePertaining to or in the wellbore (as opposed to being on the surface).
Down-hole motorA 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 rigThe machine used to drill a wellbore.
Drillpipe or Drill pipeTubular 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 stringThe combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.
FlowbackThe 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 drillingA 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 fracturingA 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.
HydrocarbonA 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.
i


Mesh sizeThe 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 motorsA 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 liquidsComponents 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 unitA 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.
PluggingThe 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.
PlugA 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 inchA unit of pressure. It is the pressure resulting from a one pound force applied to an area of one square inch.
Pressure pumpingServices that include the pumping of liquids under pressure.
Producing formationAn 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.
ProppantSized 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 playAccumulation of hydrocarbons known to exist over a large area.
ShaleA fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.
Tight oilConventional 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 sandsA type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.
TubularsA 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 wellA 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.
WellboreThe physical conduit from surface into the hydrocarbon reservoir.
Well stimulationA 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.
WirelineA 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.
WorkoverThe 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.


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

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

    Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act and the Private Securities Litigation Reform Act of 1995. In particular, the factors discussed in this report could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about:

the levels of capital expenditures by our customers and the impact of drilling and completions activity on utilization and pricing for our oilfield services;
the volatility of oil and natural gas prices and actions by OPEC members and other oil exporting nations, or OPEC+, affecting commodity price and production levels;
employee retention and increasingly competitive labor market;
general economic, business or industry conditions and concerns over a potential economic slowdown or recession;
conditions in the capital, financial and credit markets;
conditions of U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;
U.S. and global economic conditions and political and economic developments, including the energy and environmental policies;
inflationary pressure on the cost of services, equipment and other goods in our industries and other sectors;
our ability to comply with the applicable financial covenants and other terms and conditions under our new revolving credit facility and new term loan;
our ability to execute our business and financial strategies;
our plans with respect to any stock repurchases under the board of directors’ authorized stock repurchase program;
our ability to continue to grow our infrastructure services segment or recommence certain of our suspended oilfield services;
any loss of one or more of our significant customers and its impact on our revenue, financial condition and results of operations;
asset impairments;
our ability to identify, complete and integrate acquisitions of assets or businesses;
our ability to receive, or delays in receiving, permits and governmental approvals and/or payments, and to comply with applicable governmental laws and regulations;
the results of litigation relating to the contracts awarded to our subsidiary Cobra Acquisitions LLC, or Cobra, by the Puerto Rico Electric Power Authority, or PREPA;
the outcome of our ongoing efforts to collect the amounts that remain unpaid to us by PREPA for electric grid restoration services performed by our subsidiary Cobra in Puerto Rico;
the outcome or settlement of our litigation matters discussed in this report on our financial condition and cash flows;
any future litigation, indemnity or other claims;
regional supply and demand factors, delays or interruptions of production, and any governmental order, rule or regulation that may impose production limits on our customers;
shortages, delays in delivery and interruptions in supply of major components, replacement parts, or other equipment, supplies or materials;
the availability of transportation, pipeline and storage facilities and any increase in related costs;
extreme weather conditions in areas where we provide well completion, drilling and infrastructure services;
access to and restrictions on use of sourced or produced water;
technology;
civil unrest, war, military conflicts or terrorist attacks;
cyberattacks and any resulting loss of information;
competition within the energy services industry;
availability of equipment, materials or skilled personnel or other labor resources;
payment of any future dividends;
future operating results; and
capital expenditures and other plans, objectives, expectations and intentions.


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    All of these types of statements, other than statements of historical fact included in this annual report, are forward-looking statements. These forward-looking statements may be found in the “Business,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and other sections of this annual report. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “would,” “expect,” “plan,” “project,” “budget,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective,” “continue,” “will be,” “will benefit,” or “will continue,” the negative of such terms or other comparable terminology.

    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.
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PART I.

Item 1. Business

Overview
    
     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.

The growth of our industrial businesses is ongoing. We offer infrastructure engineering services focused on the transmission and distribution industry and also have equipment manufacturing operations and offer fiber optic services. Our equipment manufacturing operations provide us with the ability to repair much of our existing equipment in-house, as well as the option to manufacture certain new equipment we may need in the future. Our fiber optic services include the installation of both aerial and buried fiber. We are continuing to explore other opportunities to expand our industrial business lines.

    Our facilities and service centers are strategically located in Ohio, Texas, Oklahoma, Wisconsin, Kentucky, California, Colorado, Oregon, Indiana and Alberta, Canada primarily to serve the following areas:

The Utica Shale in Eastern Ohio;
Southern Ohio;
The Permian Basin in West Texas;
The Appalachian Basin in the Northeast;
The SCOOP and STACK in Oklahoma;
The Arkoma Basin in Arkansas and Oklahoma;
The Anadarko Basin in Oklahoma;
The Marcellus Shale in West Virginia and Pennsylvania;
Southeastern New Mexico;
The Barnett Shale in Texas;
The Granite Wash and Mississippi Shale in Oklahoma and Texas;
The Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma;
Southern California; and
The oil sands in Alberta, Canada.

    Our operational division heads have an extensive track record in the oilfield service and infrastructure businesses with an average of over 31 years of oilfield services experience and over 26 years of infrastructure services experience. They bring valuable expertise and long-term customer relationships to our business. We provide our well completion, natural sand proppant, drilling and other services to a diversified range of both public and private independent oil and natural gas producers and our infrastructure services to private utilities, public investor owned utilities, or IOUs, and cooperatives, or Co-Ops.


Our Services

    Our revenues, operating income (loss) and identifiable assets are primarily attributable to four reportable segments: well completion services, infrastructure services, natural sand proppant services and drilling services.

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Well Completion Services

    Pressure Pumping. We provide pressure pumping services, also known as hydraulic fracturing, to exploration and production companies. Fracturing services are performed to enhance the production of oil and natural gas from formations having low permeability such that the flow of hydrocarbons is restricted. We have significant expertise in multistage fracturing of horizontal oil and natural gas producing wells in shale and other unconventional geological formations. Currently, we provide pressure pumping services in the Utica Shale of Eastern Ohio, the Marcellus shale in the Appalachian Basin, and the mid-continent region in Oklahoma.

    The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, in our case primarily sand or ceramic beads, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return for the operator.

    We refer to the group of fracturing units, other equipment and vehicles necessary to perform a typical fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” We usually operate on a 24-hour-per-day basis and we typically staff three crews per fleet. All of our fracturing units and high-pressure pumps are manufactured to our specifications to enhance the performance and durability of our equipment and meet our customers’ needs.

    Each hydraulic fracturing fleet includes a mobile, on-site control center that monitors pressures, rates and volumes, as applicable. From there, our field-level managers supervise the job site by radio. Each control center is equipped with high bandwidth satellite hardware that provides continuous upload and download of job telemetry data. The data is delivered on a real-time basis to on-site job personnel, the operator and personnel at our headquarters for display in both digital and graphical form.

    An important element of fracturing services is determining the proper fracturing fluid, proppants and injection program to maximize results. In virtually all of our hydraulic fracturing jobs, our customers specify the composition of the fracturing fluid to be used. The fracturing fluid may contain hazardous substances, such as hydrochloric acid and certain petrochemicals. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water. The customers remove the water from the well using a controlled flow-back process, and we are generally not involved in that process or in the disposal of the fluid.

    We own and operate fleets of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of a high-pressure hydraulic pump, an engine, a transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted to a flat-bed trailer. As of December 31, 2023, our pressure pumping business included six high-pressure fleets consisting of an aggregate 128 high-pressure fracturing units with pump nameplate capacity of 310,000 horsepower. One of our six pressure pumping fleets was staffed and providing services in the northeast region as of December 31, 2023. Over the past two years, we have converted two fleets to include dynamic gas blending, or DGB, capabilities to meet recent shifts in customer demand. Further, subject to market conditions and liquidity requirements, we have plans to upgrade one additional fleet in 2024. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Industries—Oil and Natural Gas Industry” for additional information.

    Sand Hauling. Our sand hauling services provide last-mile trucking and logistics services for proppant used in completion activities in the Utica Shale and SCOOP/STACK. As of December 31, 2023, we owned a fleet of 39 trucks.

    Water Transfer. Our water transfer services provide water sourcing and water transfer services primarily for completion activities in the mid-continent region. As of December 31, 2023, we owned 121 water transfer pumps and 91 miles of layflat hose.

    Master Services Agreements. We contract with most of our well completion customers under master service agreements, or MSAs. Generally, our MSAs, including those relating to our hydraulic fracturing services, specify payment terms, audit rights and insurance requirements and allocate certain operational risks through indemnity and similar provision.

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Infrastructure Services

    Our infrastructure services business provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. We offer a broad range of services on electric transmission and distribution, or T&D, networks and substation facilities, which include engineering, design, construction, upgrade, maintenance and repair of high voltage transmission lines, substations and lower voltage overhead and underground distribution systems. Our commercial services include the installation, maintenance and repair of commercial wiring. We also provide storm repair and restoration services in response to storms and other disasters. We provide infrastructure services primarily in the northeast, southwest, midwest and western portions of the United States.

    We currently have agreements in place with private utilities, public IOUs and Co-Ops. Since we commenced operations in this line of business, a substantial portion of our infrastructure revenue has been generated from storm restoration work, primarily from the Puerto Rico Electric Power Authority, or PREPA, due to damage caused by Hurricane Maria. On October 19, 2017, Cobra Acquisitions LLC, or Cobra, and PREPA entered into an emergency master services agreement for repairs to PREPA’s electrical grid. The one-year contract, as amended, provided for payments of up to $945 million. 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. Our work under each of the contracts with PREPA ended on March 31, 2019. 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.

    As of December 31, 2023, PREPA owed Cobra approximately $204.8 million for services performed, excluding $197.5 million of interest charged on delinquent balances. Subsequent to December 31, 2023, PREPA paid an aggregate of $64.0 million with respect to the PREPA account receivable, of which $9.6 million was paid to Cobra and $54.4 million was paid to SPCP Group, LLC (“SPCP Group”) under the assignment agreement with Cobra, pursuant to which on December 1, 2023, Cobra transferred approximately $54.4 million of its outstanding PREPA receivable to SPCP Group in exchange for Cobras receipt of $46.1 million in net proceeds. Following the payment of $54.4 million to SPCP Group, all of Cobra’s and Mammoth’s obligations under the assignment agreement were fully extinguished and the agreement was terminated. See Note 2. Summary of Significant Accounting Policies—Accounts Receivable and Note 20. Commitments and Contingencies to our consolidated financial statements and Item 1A., and “Risk Factors—Risks Related to Our Business and the Industries We Serve” included elsewhere in this annual report for more information regarding these delinquent balances as well as other legal actions and governmental investigations related to our work for PREPA, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cobra Assignment Agreement” for additional information regarding the assignment agreement with SPCP Group.

During 2022, operational improvements combined with increased crew count drove enhanced results in our infrastructure services division compared to 2021. Although our average crew count declined slightly from approximately 91 crews throughout 2022 to approximately 83 crews throughout 2023, operational efficiencies drove comparable results. Funding for projects in the infrastructure space remains strong with added opportunities expected from the Infrastructure Investment and Jobs Act, which was signed into law on November 15, 2021. We anticipate the federal spending to begin fueling additional projects in this sector and expect bidding activity to ramp up in 2024. We continue to focus on operational execution and pursue opportunities within this sector as we strategically structure our service offerings for growth, intending to increase our infrastructure services activity and expand both our geographic footprint and depth of projects, especially in fiber maintenance and installation projects.

We work for multiple utilities primarily across the northeastern, southwestern, midwestern and western portions of the United States. We believe that we are well-positioned to compete for new projects due to the experience of our infrastructure management team, combined with our vertically integrated service offerings. We are seeking to leverage this experience and our service offerings to grow our customer base and increase our revenues in the continental United States over the coming years.

Natural Sand Proppant Services

    In our natural sand proppant business, we mine, process and sell sand. In the past, we have also bought processed sand from suppliers on the spot market for resale. Natural sand proppant, also known as frac sand, is the most widely used type of proppant due to its broad applicability in unconventional oil and natural gas wells and its cost advantage relative to other proppants. Natural frac sand may be used as proppant in all but the highest pressure and temperature environments and is being employed in nearly all major U.S. unconventional oil and natural gas producing basins, including those in which we operate.

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    At our Barron County and Jackson County, Wisconsin plants, we mine and process sand into premium monocrystalline sand, a specialized mineral that is used as frac sand. We can also purchase raw or washed sand and process it at our indoor sand processing plant located in Pierce County, Wisconsin; however, this facility has been temporarily idled since September 2018 due to market conditions. We sell sand to our customers for use in their hydraulic fracturing operations to enhance recovery rates from unconventional wells. Our sand processing plants produce a range of frac sand sizes for use in all major North American shale basins, including a majority of the standard proppant sizes as defined by the ISO/API 13503-2 specifications. These grain sizes can be customized to meet the demands of our customers with respect to a specific well. Our supply of Jordan substrate exhibits the physical properties necessary to withstand the completion and production environments of the wells in these shale basins. Our indoor processing plant in Pierce County, Wisconsin is designed for year-round continuous wet and dry plant operation. Our multi-environment processing plants in Barron County and Jackson County, Wisconsin have indoor dry plants designed to operate year-round and outdoor wet plants that generally operate eight months per year.

    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.

In the fourth quarter of 2023, we entered into a sand supply agreement with a third-party service provider. Under the terms of the agreement, we have agreed to supply, in aggregate, approximately 709 thousand tons of sand over the contract period of 12 months.

Drilling Services

Due to market conditions, we temporarily shut-down our rig moving services in April 2020 and our contract land drilling operations beginning in December 2019. We continue to maintain our equipment and monitor market conditions to determine if and when we will recommence these services.

Directional Drilling. Our directional drilling services provide for the efficient drilling and production of oil and natural gas from unconventional resource plays. Our directional drilling equipment includes mud motors used to propel drill bits and kits for measurement-while-drilling, or MWD, and electromagnetic, or EM, technology. MWD kits are down-hole tools that provide real-time measurements of the location and orientation of the bottom-hole assembly, which is necessary to adjust the drilling process and guide the wellbore to a specific target. This technology, coupled with our complementary services, allows our customers to drill wellbores to specific objectives within narrow location parameters within target horizons. The evolution of unconventional resource reserve recovery has increased the need for the precise placement of a wellbore. Wellbores often travel across long-lateral intervals within narrow formations as thin as ten feet. Our personnel are involved in all aspects of a well from the initial planning of a customer’s drilling program to the management and execution of the horizontal or directional drilling operation.

    As of December 31, 2023, we owned four MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 89 mud motors, nine air motors and an inventory of related parts and equipment. Currently, we perform our directional drilling services in the Utica Shale, Anadarko Basin, Arkoma Basin, Powder River Basin and Permian Basin.

Contract Drilling. As part of our contract drilling services, we provided both vertical and horizontal drilling services to customers in the Permian Basin of West Texas. As of December 31, 2023, we owned 11 land drilling rigs, ranging from 800 to 1,600 horsepower, seven of which are specifically designed for drilling horizontal and directional wells.

    Our drilling rigs have rated maximum depth capabilities ranging from 12,500 feet to 20,000 feet. Of these drilling rigs, six are electric rigs and five are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the power from its generators (which in the case of mechanical rigs, power the rig directly) into electricity to power the rig. Depth
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and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job. Power requirements for drilling jobs may vary considerably, but most of our mechanical drilling rigs employ six engines to generate between 800 and 1,200 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations drill to measured depths greater than 10,000 to 18,000 feet. Generally, land rigs operate with four crews of five people and two tool pushers, or rig managers, rotating on a weekly or bi-weekly schedule.

    We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs.

    Prior to our temporary shutdown of these services in December 2019, we obtained our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. We typically entered into drilling contracts that provided for compensation on a daywork basis. Occasionally, we entered into drilling contracts that provided for compensation on a footage basis; however, a majority of such footage drilling contracts also provided for daywork rates for work outside core drilling activities contemplated by such footage contracts and under certain other circumstances. We have not historically entered into turnkey contracts; however, we may decide to enter into such contracts in the future. It is also possible that we may acquire such contracts in connection with future acquisitions of drilling assets. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, the anticipated duration of the work to be performed and market conditions.

Rig Moving. We provided rig moving services in the Permian Basin. Due to market conditions, we temporarily shut-down our rig moving operations beginning in April 2020. As of December 31, 2023, we owned 15 trucks specifically tailored to move rigs.

Other Services

    We also offer a variety of other services including aviation services, equipment rental services, remote accommodation services and equipment manufacturing services. Additionally, during certain of the periods discussed in this report, we offered coil tubing services, pressure control services, flowback services, crude oil hauling services, cementing services and acidizing services.
    
Aviation Services. Our aviation services include leasing helicopters to customers for use primarily in the electrical utility industry. Additionally, we provide helicopter training and response services. As of December 31, 2023, we owned two helicopters.

    Equipment Rentals. Our equipment rental services provide a wide range of oilfield related equipment used in drilling, flowback and hydraulic fracturing services. Our equipment rentals consist of cranes, light plants, generators and other oilfield related equipment. We provide equipment rental in the Permian Basin, Utica Shale and Marcellus Shale.

    Remote Accommodations. Our remote accommodations business provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We provide a turnkey solution for our customers’ accommodation needs. These modular camps, when assembled together, form large dormitories, with kitchen/dining facilities and recreation areas. These camps are operated as “all inclusive,” where meals are prepared and provided for the guests. The primary revenue source for these camps is lodging fees. As of December 31, 2023, we had a capacity of 878 rooms, 612 of which are at Sand Tiger Lodge, our camp in northern Alberta, Canada, and 266 of which are available to be leased as rental equipment to a third party. On average, 178 rooms were utilized per night during the year ended December 31, 2023.

    Equipment Manufacturing. Our equipment manufacturing operations, which are located at our facility in Oklahoma, have primarily served our internal needs for our pressure pumping, water transfer, equipment rental and infrastructure businesses, but we have the ability to expand into third party sales in the future.

    We also offered coil tubing services, pressure control services, flowback services, crude oil hauling services, cementing services and acidizing services during certain of the periods discussed in this report. Due to market conditions, we temporarily shut down our flowback, cementing and acidizing operations beginning in July 2019, our coil tubing, pressure control and full service transportation operations beginning in July 2020 and our crude oil hauling operations beginning in July 2021. We continue to maintain our equipment and monitor market conditions to determine if and when we will recommence these services.    

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    Flowback. Our flowback services consisted of production testing, solids control, hydrostatic testing and torque services. Flowback involves the process of allowing fluids to flow from the well following a treatment, either in preparation for an impending phase of treatment or to return the well to production. Our flowback equipment consists of manifolds, accumulators, valves, flare stacks and other associated equipment. We provided flowback services in the Appalachian Basin, the Eagle Ford Shale, the Haynesville Shale and mid-continent markets. As of December 31, 2023, we owned 20 solids control packages, four hydrostatic testing packages and seven torque service packages.

    Cementing and Acidizing. We provided cementing and acidizing services in the Permian Basin. Cementing services involve preparing and pumping cement into place in a wellbore to support and protect well casings and help achieve zonal isolation. Acidizing services involve pumping acid into a wellbore to improve productivity or injectivity. As of December 31, 2023, we owned four acidizing pumps.
    
    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, 2023, we owned 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.

    Pressure Control. Our pressure control services consisted of nitrogen and fluid pumping services. Our pressure control services equipment is designed to support activities in unconventional resource plays with the ability to operate under high pressures without having to delay or cease production during completion operations. Ceasing or suppressing production during the completion phase of an unconventional well could result in formation damage impacting the overall recovery of reserves. Our pressure control services helped operators minimize the risk of such damage during completion activities. As of December 31, 2023, we had a total of four nitrogen pumping units and five fluid pumping units. We provided pressure control services in the Eagle Ford Shale and the Permian Basin.

Nitrogen Services. Nitrogen services involve the use of nitrogen, an inert gas, in various pressure pumping operations. When provided as a stand-alone service, nitrogen is used in displacing fluids in various oilfield applications. As of December 31, 2023, we had a total of four nitrogen pumping units capable of pumping at a rate of up to 3,000 standard cubic feet per minute with pressures up to 10,000 psi. Pumping at these rates and pressures is typically required for the unconventional oil and natural gas resource plays we serve.
Fluid Pumping Services. Fluid pumping services consist of maintaining well pressure, pumping down wireline tools, assisting coiled tubing units and the removal of fluids and solids from the wellbore for clean-out operations. As of December 31, 2023, we had five fluid pumping units. Three of these units are coiled tubing double pump units capable of output of up to eight barrels per minute and are rated for pressures up to 15,000 psi. Two of these units are quintuplex pump units capable of output of up to 15 barrels per minute and are rated for pressures up to 15,000 psi.

Full Service Transportation. During 2019, we expanded our trucking operations to include brokering and hauling of general freight throughout the United States. As of December 31, 2023, we had a fleet of six trucks.

    Crude Oil Hauling. We provided crude transportation services in the Permian Basin and mid-continent region. As of December 31, 2023, we had a fleet of 13 crude oil hauling trucks.

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Our Industries

Oil and Natural Gas Industry

    The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and related services and products budgets. The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity, storage capacity, shortages of equipment and materials and other conditions and factors that are beyond our control.

    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 driven by many factors, including 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. We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services during 2022. Throughout 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion activities for our customers, in particular, in the Utica and Marcellus Shale natural gas plays, and, as a result, reduced demand for our well completion services. These factors have continued into the first quarter of 2024. Despite this short-term softness, however, we are seeing indications that activity levels will begin to ramp back up in mid-2024, creating the opportunity to reactivate additional fleets, if appropriate. The ongoing war in Ukraine and the recent Israel-Hamas war, however, could continue to have an adverse impact on the global energy markets and volatility of commodity prices, which could further adversely impact demand for our well completion services.

In response to market conditions, we temporarily shut down our cementing and acidizing operations and flowback operations beginning in July 2019, our contract drilling operations beginning in December 2019, our rig hauling operations beginning in April 2020, our coil tubing, pressure control and full service transportation operations beginning in July 2020 and our crude oil hauling operations beginning in July 2021. We continue to monitor the market to determine if and when we can recommence these services.

Natural Sand Proppant Industry

We experienced a significant decline in demand of our sand proppant in the second half of 2019 and throughout 2020 as a result of completion activity falling due to lower oil demand and pricing, increased capital discipline by our customers, budget exhaustion and the COVID-19 pandemic. Activity rebounded modestly in 2021 and continued to increase throughout 2022 as we saw an increase in the volume of sand sold. Supply constraints from labor shortages negatively affected West Texas in-basin mine operations and increased demand for Northern White frac sand for the region in 2022. Demand from oil and gas companies in Western Canada and the Marcellus Shale was also strong in 2022. The increase in activity in 2022 resulted in an increase in demand and pricing for our sand, which continued throughout the first quarter of 2023. Demand for our natural sand proppant was adversely impacted in the second quarter of 2023 by the wildfires in Canada, which hindered our ability to transport sand. Notwithstanding the foregoing, our sand business remained resilient during the second quarter of 2023. As discussed above, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion activities and adversely impacted demand for our sand proppant services in the second half of 2023. We are beginning to see an uptick in orders for our sand in the first quarter of 2024.

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 size) and finer grades (40/70 and 100 mesh size). Our sample boring data and our historical production data have indicated that our reserves contain deposits of approximately 60% 40 mesh size or finer 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.

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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 a cost advantage over many of 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.

Energy Infrastructure Industry

    The energy infrastructure industry involves the construction and maintenance of the electrical power grid, including power generation, high voltage transmission lines, substations and low voltage distribution lines, all of which connect power generation facilities to end users. The industry also provides storm repair and restoration services in response to storms and other disasters.

Demand for our services is driven by the repair and construction of transmission lines, fiber lines, substations and distribution networks and is determined by the level of expenditures of utility companies. While expansion of the electrical grid is occurring, the majority of capital expenditures spent in recent years has surrounded the repair and maintenance of existing networks. Another factor that significantly influences the level of spending in the industry are natural disasters, including thunderstorms, ice storms, snow storms, tornadoes, hurricanes, earthquakes, wildfires and lightning strikes, all of which can impact the electrical grid.

Certain barriers to entry exist in the markets in which we operate, including adequate financial resources, technical expertise, high safety ratings and a proven track record of operational success. We compete based upon our industry experience, technical expertise, financial and operational resources, geographic presence, industry reputation, safety record and customer service. While we believe our customers consider a number of factors when selecting a service provider, they generally award most of their work through a bid process. Consequently, price is often a principal factor in determining which service provider is selected.

We believe that the age of the existing infrastructure across the United States and the spending trends in North America will benefit our operations and our ability to achieve our business objectives. Funding for projects in the infrastructure space remains strong with added opportunities expected from the Infrastructure Investment and Jobs Act, which was signed into law on November 15, 2021.

Our Strengths

    Our primary business objective is to grow our operations and create value for our stockholders through organic growth opportunities and accretive acquisitions. We believe that the following strengths position us well to capitalize on activity in unconventional resource plays and achieve our primary business objective:

Strategic geographic positioning. We currently operate facilities and service centers to support our oilfield service operations in major unconventional resource plays in the United States, including the Utica Shale in Eastern Ohio, the Permian Basin in West Texas and Southeastern New Mexico, the SCOOP/STACK in Oklahoma, the Marcellus Shale in West Virginia, the Granite Wash in Oklahoma and Texas, the Cana Woodford Shale in Oklahoma and the oil sands in Alberta, Canada. We currently operate infrastructure facilities and service centers to support our infrastructure operations in the northeastern, southwestern, midwestern and western portions of the United States. We believe our geographic positioning within active oil and natural gas liquids resource plays will benefit us strategically as activity increases in these unconventional resource plays.

Experienced management and operating team. Our operational division heads have an extensive track record in the oilfield and infrastructure service businesses with an average of over 31 years of oilfield services experience and over 26 years of infrastructure services experience. In addition, our field managers have expertise in the areas in which they operate and understand the challenges that our customers face. We believe their knowledge of our industries and business lines enhances our ability to provide innovative, client-focused and basin-specific customer service, which we also believe strengthens our relationships with our customers.

Fleet of equipment. Our oilfield service fleet is predominantly comprised of equipment designed to optimize recovery from unconventional wells and our infrastructure service fleet is predominantly comprised of equipment designed to construct and repair electric transmission and distribution lines. We believe that our fleet of quality equipment will allow us to provide a high level of service to our customers. In addition, we have converted two fleets of our pressure
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pumping units to include DGB capabilities to meet recent shifts in customer demand and expect to convert one additional fleet during 2024, subject to market conditions and liquidity requirements.

Our Business Strategy

    We intend to achieve our primary business objective by the successful execution of our business plan to strategically deploy our equipment and personnel to provide well completion services, natural sand proppant services and other energy services in unconventional resource plays, including the Utica Shale in Ohio, the SCOOP/STACK in Oklahoma and the Marcellus Shale in West Virginia. We intend to achieve our primary business objective in connection with our infrastructure services by the successful execution of our business plan to strategically deploy equipment and personnel to provide infrastructure services across the United States. We believe our infrastructure services optimize our customers’ ability to maintain, improve and expand their infrastructure and that our oil and natural gas services optimize our customers’ ultimate resources recovery and present value of hydrocarbon reserves. We seek to create cost efficiencies for our customers by providing a suite of complementary services designed to address a wide range of our customers’ needs. Specifically, we strive to create value for our stockholders through the following strategies:

Leverage our broad range of services for cross-selling opportunities. We offer a complementary suite of services and products. Our well completion services division provide hydraulic fracturing services for unconventional wells as well as sand hauling services 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 for hydraulic fracturing. Additionally, we provide directional drilling services, equipment rentals, remote accommodations and equipment manufacturing. We intend to leverage our existing customer relationships and operational track record to cross sell our services and increase our exposure and product offerings to our existing customers, broaden our customer base and expand opportunistically to other geographic regions in which our customers have operations, as well as to create operational efficiencies for our customers.

Expand our energy infrastructure business. On November 15, 2021, President Biden signed the Infrastructure Investment and Jobs Act into law. This is expected to bring new opportunities in the infrastructure industry, including new fiber-related projects. We consistently monitor market conditions and intend to expand the capacity and scope of our energy infrastructure services as demand warrants in geographic areas in which we currently operate, as well as in new geographic areas.

Capitalize on activity in the unconventional resource plays. Our oil and natural gas service equipment is designed to provide a broad range of services for unconventional wells, and our operations are strategically located in major unconventional resource plays. During 2023, oil prices fluctuated between a low of $66.74 on March 17, 2023, and a high of $93.68 on September 27, 2023, and averaged $77.61 per barrel for the year. We saw a decline in commodity pricing during 2023, resulting in lower utilization and margins for our oilfield services divisions.

Maintain a conservative balance sheet. We seek to maintain a conservative balance sheet, which allows us to better react to changes in commodity prices and related demand for our services, as well as overall market conditions. During 2023, we reduced our outstanding debt balance by $40.7 million, from $83.5 million as of December 31, 2022 to $42.8 million as of December 31, 2023.

Expand our services to meet expanding customer demand. The scope of services for horizontal wells is greater than that for conventional wells. Industry analysts have reported that the average horsepower required for current completion designs, amount of sand per lateral foot, length of lateral and number of fracture stages has continued to increase since 2008. We consistently monitor market conditions and intend to expand the capacity and scope of our business lines if, and when, demand warrants in resource plays in which we currently operate, as well as in new resource plays. If we perceive unmet demand in our principal geographic locations for different service lines and subject to our liquidity needs, we will seek to expand our current service offerings to meet that demand.

Leverage our experienced operational management team expertise. We seek to manage the services we provide as closely as possible to the needs of our customer base. Our operational division heads have long-term relationships with our largest customers. We intend to leverage these relationships and our operational management team’s expertise to deliver innovative, client focused and services to our customers.

Expand through selected, accretive acquisitions. To complement our organic growth and subject to our liquidity needs, we intend to pursue selected, accretive acquisitions of businesses and assets, primarily related to our infrastructure
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services, completion and production services and industrial based companies, that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence. We believe this approach will help facilitate the strategic expansion of our customer base, geographic presence and service offerings. We also believe that our industry contacts and those of Wexford Capital LP (“Wexford”), our largest stockholder, may help us identify acquisition opportunities. We may use our common stock as consideration for accretive acquisitions.

Marketing and Customers

    Our customers consist primarily of independent oil and natural gas producers, land-based drilling contractors, private utilities, IOUs, and Co-Ops in North America. For the years ended December 31, 2023, 2022 and 2021, we had approximately 360, 410 and 480 customers, respectively, including Hilcorp Energy, Devon Energy Corporation, Arsenal Resources, Camino Natural Resources, LLC and Overland Contracting Inc. Our top five customers accounted for approximately 35%, 36% and 35%, respectively, of our revenue for the years ended December 31, 2023, 2022 and 2021. Although we believe we have a broad customer base and wide geographic coverage of operations, it is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer decides not to continue to use our services and is not replaced by new or existing customers, our revenue would decline and our operating results and financial condition would be harmed.

Operating Risks and Insurance

    Our operations are subject to hazards inherent in the energy services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause:

personal injury or loss of life;
damage or destruction of property, equipment, natural resources and the environment; and
suspension of operations.

    In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.

    Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

    Despite our efforts to maintain safety standards, from time to time we have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

    We maintain commercial general liability, workers’ compensation, business auto, commercial property, motor truck cargo, umbrella liability, professional liability, cybersecurity, in certain instances, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. With respect to our hydraulic fracturing operations, coverage would be available under our policy for any surface or subsurface environmental clean-up and liability to third parties arising from any surface or subsurface contamination. We also have certain specific coverages for some of our businesses, including our remote accommodation services, pressure pumping services, directional drilling services and infrastructure engineering services.

    Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See Item 1A. “Risk Factors” for a description of certain risks associated with our insurance policies.

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Safety and Remediation Program

    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.

    Historically, we have used third-party contractors to provide remediation and spill response services when necessary to address spills that were beyond our containment capabilities. None of these prior spills were significant, and we have not experienced any material incidents, citations or legal proceeding relating to our hydraulic fracturing or crude hauling services for environmental concerns. To the extent our hydraulic fracturing or other energy services operations result in a future spill, leak or other environmental impact that is beyond our ability to contain, we intend to engage the services of such remediation company or an alternative company to assist us with clean-up and remediation.

Competition

    The markets in which we operate are highly competitive. To be successful, a company must provide services and products that meet the specific needs of oil and natural gas exploration and production companies, drilling services contractors, private utilities, IOUs and Co-Ops at competitive prices.

    We provide our services and products across the United States and in Alberta, Canada and we compete against different companies in each geographic area and service and product line we offer. Our competition includes many large and small energy service companies, including the largest integrated oilfield services companies and energy infrastructure companies. Our major competitors in well completion services include Halliburton Company, Universal Pressure Pumping, Inc., NexTier Oilfield Solutions, Inc., RPC Incorporated, Liberty Oilfield Services, Inc. and ProFrac Holding Corp. Our major competitors for our infrastructure services business include MYR Group, Inc., Quanta Services, Inc., MasTec, Inc. and EMCOR Group, Inc. Our major competitors in our natural sand proppant services business are 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.

    We believe that the principal competitive factors in the market areas that we serve are quality of service and products, reputation for safety, technical proficiency, availability and price. While we must be competitive in our pricing, we believe our customers select our services and products based on the local leadership and expertise that our field management and operating personnel use to deliver quality services and products.

Regulation

    We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, permitting and inspection requirements applicable to construction projects, building and electrical codes regulations, government project regulations, the handling of hazardous materials, the transportation of explosives, the protection of human health and the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance which is incorporated into our daily operating procedures. The oil and natural gas and infrastructure industries are subject to environmental and other regulation pursuant to local, state and federal legislation.

Transportation Matters

    In connection with the transportation and relocation of our equipment and shipment of frac sand, crude oil and general cargo, 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
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operations, driver licensing and 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 Federal Motor Carrier Safety Administration, or FMCSA, a unit within 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.

    Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria which could result in a suspension of operations. The rating scale consists of “satisfactory,” “conditional” and “unsatisfactory” ratings. As of December 31, 2023, all of our trucking operations have “satisfactory” ratings with the Department of Transportation. We have undertaken comprehensive efforts that we believe are adequate to comply with the regulations. Further information regarding our safety performance is available at the FMCSA website at www.fmcsa.dot.gov.

    In December 2010, the FMCSA launched a program called Compliance, Safety, Accountability, or CSA, in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System, or SMS, which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow FMCSA to identify carriers with safety issues and intervene to address those problems. However, the agency has announced a future intention to revise its safety rating system by making greater use of SMS data in lieu of on-site compliance audits of carriers. At this time, we cannot predict the effect such a revision may have on our safety rating.

Environmental Matters and Regulation

    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.

    Waste Handling. We handle, transport, store and dispose of wastes that are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions.

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    Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Several environmental organizations have also petitioned the EPA to modify existing regulations to recategorize certain oil and natural gas exploration, development and production wastes as “hazardous.” Also, in December 2015, the EPA agreed in a consent decree to review its regulation of oil and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

    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.

    NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials associated with oil and gas deposits and, accordingly may result in the generation of wastes and other materials containing naturally occurring radioactive materials, or NORM. NORM exhibiting levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because certain of the properties presently or previously owned, operated or occupied by us may have been used for oil and gas production operations, it is possible that we may incur costs or liabilities associated with NORM.

    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 January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015. However on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the CWA. On September 8, 2023, the EPA and the Corps published a final rule conforming their regulations to the Supreme Court decision. These recent actions have provided some clarity. However, to the extent the EPA and the Corps broadly interpret their jurisdiction and 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.

    The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “—
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Regulation of Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Also, spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Noncompliance with these requirements may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations.

    Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, our sand proppant services operations are subject to air permits issued by the Wisconsin Department of Natural Resources regulating our emission of fugitive dust and other constituents. These and other laws and regulations may increase the costs of compliance for some facilities where we operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas and infrastructure projects.

    Climate Change. In recent years, federal, state and local governments have taken steps to reduce emissions of carbon dioxide, methane and other greenhouse gases, collectively referred to as GHGs. For example, the Infrastructure Investment and Jobs Act of 2021 and the Inflation Reduction Act of 2022 (the “IRA”) include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge, which will be phased-in starting in 2024. On January 12, 2024, the EPA announced a proposed rule to implement the methane emissions charge. These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels towards lower or zero carbon emissions alternatives, which could decrease demand for our well completion, natural sand proppant and other services related to the oil and natural gas industry.

The EPA has also finalized a series of GHG monitoring, reporting and emissions control rules for the oil and natural gas industry, and almost one-half of the states have taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. Also, states have imposed increasingly stringent requirement related to the venting or flaring of gas during oil and gas operations.

    At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its greenhouse gas emissions by 50 to 52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and other world leaders made further commitments to reduce greenhouse gas emission, including reducing global methane emissions by at least 30 percent by 2030 (from 2020 levels) to meet this objective. More than 150 countries have now signed on to this pledge. Most
recently, at the 28th Conference of the Parties in the United Arab Emirates, world leaders agreed to transition away from fossil fuels in a just, orderly and equitable manner and to triple renewables and double energy efficiency globally by 2030. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international commitments.

    In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against certain energy companies and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

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    Moreover, climate change may cause more extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our productivity and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Endangered Species Act

    Environmental laws such as the Endangered Species Act, as amended, or the ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Regulation of Hydraulic Fracturing

    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 December 2, 2023, the EPA announced a final 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
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of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries and prohibiting venting of natural gas in certain situations. In July 2023, the Biden Administration also announced a new Cabinet-level task force aimed at detecting and cracking down on methane leaks. These new standards, 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. Also, on July 24, 2023, the BLM published a
proposed rule to update its oil and gas leasing regulations, which would increase bonding requirements and raise royalty rates. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations.

    There are certain governmental reviews either underway or being proposed that focus on the environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

    Several states and local jurisdictions in which we or our customers operate have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards, require the disclosure of the composition of hydraulic fracturing fluids and/or impose restrictions on the use of produced water from hydraulic fracturing activities or moratoriums on new produced water well permits in an effort to control induced seismicity. Any increased regulation of hydraulic fracturing or related activities could reduce the demand for our services and materially and adversely affect our reserves and results of operations.

    There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our customers’ fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause us or our customers to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse
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effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Regulation of Natural Sand Proppant Services

    The MSHA has primary regulatory jurisdiction over commercial silica operations, including quarries, surface mines, underground mines and industrial mineral processing facilities. MSHA representatives perform at least two annual inspections of our production facilities to ensure employee and general site safety. To date, these inspections have not resulted in any citations for material violations of MSHA standards, and we believe we are in material compliance with MSHA requirements.

Other Regulation of the Oil and Natural Gas Industry

    The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. These binding rules and regulations are subject to changes in interpretation or enforcement. Although changes to the regulatory burden on the oil and natural gas industry could affect the demand for our services, we would not expect to be affected any differently or to any greater or lesser extent than other companies in the industry with similar operations.

    Drilling. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states, and some counties and municipalities, in which we operate also regulate one or more of the following:
the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities, including seasonal wildlife closures;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third parties.

    Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

    State Regulation. The states in which we or our customers operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but they may do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells and to limit the number of wells or locations our customers can drill.

    In 2015, the Ohio Department of Natural Resources, or the ODNR, enacted a comprehensive set of rules to regulate the construction of well pads. Under these rules, operators must submit detailed horizontal well pad site plans certified by a professional engineer for review by the ODNR Division of Oil and Gas Resources Management prior to the construction of a well pad. These rules have resulted in increased construction costs for operators. The ODNR also adopted rules that took effect January 13, 2022 addressing the siting, permitting and construction of new oil and gas facilities and disposal wells. These rules, among other things, set forth siting and setback criteria, prescribe detailed construction and operational requirements, establish insurance and financial assurance requirements, and institute requirements for decommissioning. As of January 2024, the ODNR Division of Oil and Gas Resources Management is updating sections of the Ohio Administrative Code that regulate oil and gas activity, including proposed changes to the provisions governing the design, construction, modification, and reclamation of well sites used to drill and produce horizontal oil and gas wells.

    The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
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Regulation of Infrastructure Services

    In our infrastructure business, our operations are subject to various federal, state and local laws and regulations including:

licensing, permitting and inspection requirements applicable to contractors, electricians and engineers;
regulations governing environmental and conservation matters;
regulations relating to worker safety;
permitting and inspection requirements applicable to construction projects;
wage and hour regulations;
building and electrical codes; and
special bidding, procurement and other requirements on government projects.

We believe that we have all the licenses required to conduct our energy infrastructure services and that we are in substantial compliance with applicable regulatory requirements. Our failure to comply with applicable regulations could result in substantial fines or revocation of our operating licenses, as well as give rise to termination or cancellation rights under our contracts or disqualify us from future bidding opportunities.

OSHA Matters

    We are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. Compliance with these laws and regulations has not had a material adverse effect on our operations or financial position.

Employees, Safety and Diversity

    As of December 31, 2023, we had 733 full time employees. The number of employees fluctuates depending on the current and expected demand for our services. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full-time employees.

We view our employees as our greatest asset and actively recruit talented people regardless of gender or ethnic background. We also promote diversity, inclusion and equal employment opportunities by evaluating and promoting employees based on skills and performance alone, while also seeking to attract and retain a diverse workforce and continuing to cultivate an inclusive and respectful work environment. One of six of our current board members and director nominees is ethnically diverse. Further, as of December 31, 2023, over 11% of our employees were women and 22 of 97 employees holding managerial and other key positions within the organization are women. Also, over 11% of our employees self-identify as ethnic minorities as of December 31, 2023. Further, we invest in the learning and development of our employees. We strive to identify talent and to provide employees who demonstrate exceptional performance with opportunities and training to progress to higher levels within the organization.

We maintain a culture of safety, committed to the protection of the health and safety of our employees as well as preserving the environment and our relationships with the communities in which we operate. We place a strong emphasis on the safe execution of our operations, including safety training for our employees. We have a comprehensive approach to formulating and managing training requirements for our operational employees. This includes periodic environmental, health and safety meetings, a combination of live in-person training and computer-based training tailored to specific job duties and operational activities, and comprehensive safety reference material. In addition, our safety recognition program encourages employees throughout our organization to focus on conducting operations in accordance with our strict safety standards. Further, we work closely with federal, state and local governments and community organizations to help ensure that our operations comply with legal requirements and community standards. Lastly, when our employees identify a heightened safety risk, we respond quickly to mitigate the risk through communication, coordination and, if appropriate, a change in policy, procedures and training. We believe that our customers select their operational partners based in part on the quality of their safety and compliance records, and therefore, we will continue to make investments in this area. We also empower all personnel with stop-work authority (“SWA”) as a tool for helping ensure safety. Our SWA policy empowers our employees to stop work whenever they identify unsafe work conditions. When SWA is employed, operations cease until the risk is addressed and both
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the employee and management agree that it is safe to resume work. See also “Safety and Remediation Program” below for additional information.

Availability of Company Reports

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.mammothenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the Securities and Exchange Commission (the “SEC”) .
Risk Factors Summary

The following is a summary of the principal risks that could adversely affect our business, operations and financial results. Please refer to Item 1A “Risk Factors” of this Form 10-K below for additional discussion of the risks summarized in this Risk Factors Summary.

Risks Related to Our Business and the Industries We Serve

Failure by PREPA to pay the amounts owed to our infrastructure subsidiary Cobra for services performed would materially and adversely affect our financial condition, results of operations and cash flows.
Our customer base is concentrated and the loss of one or more of our significant customers, or their failure to pay the amounts they owe us, could cause our revenue to decline substantially.
We may experience losses in excess of our recorded reserves for receivables.
Our revolving credit facility and term credit facility impose restrictions on us that may affect our ability to successfully operate our business.
Volatility in the oil and natural gas markets has negatively impacted our business in the past, and could negatively impact our oilfield services business in the future.
Governmental laws, policies, regulations and subsidies, including initiatives to promote the use of renewable energy sources could create commodity volatility and negatively impact our oilfield services business.
A transition of the global energy sector from primarily a fossil fuel-based system to renewable energy sources could affect our customers level of expenditures.
Shortages, delays in delivery and interruptions in supply of major components, replacement parts or, other equipment, supplies or materials may adversely affect our pressure pumping business and our drilling business.
Our business depends upon our ability to obtain specialized equipment and parts from third-party suppliers, and we may be vulnerable to delayed deliveries and future price increases.
Our failure to receive payment for contract change orders or adequately recover on claims brought by us against customers related to payment terms and costs could materially and adversely affect our business.
We may not accurately estimate the costs associated with infrastructure services provided under fixed price contracts, which could adversely affect our business, financial condition and cash flows.
We may be unable to obtain sufficient bonding capacity to support certain service offerings, and the need for performance and surety bonds could reduce availability under our credit facility.
The nature of our infrastructure services business exposes us to potential liability for warranty claims and faulty engineering, which may reduce our profitability.
Delays and reductions in government appropriations can negatively impact energy infrastructure engineering, design, construction, maintenance and repair projects and may impair the ability of our energy infrastructure customers to timely pay for products or services provided or result in their insolvency or bankruptcy.
Future performance of our natural sand proppant services business will depend on our ability to appropriately react to potential fluctuations in the demand for and supply of frac sand.
Increasing transportation and related costs could have a material adverse effect on our business.
Diminished access to water and inability to secure or maintain necessary permits may adversely affect operations of our frac sand processing plants.
Development of permanent infrastructure in the Canadian oil sands region or other locations where we locate our remote accommodations could negatively impact our remote accommodations business.
In the course of our business, we may become subject to lawsuits, indemnity or other claims, which could materially and adversely affect our business, results of operations and cash flows.
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We rely on a few key employees and skilled and qualified workers whose absence or loss could adversely affect our business.
Our operations may be limited or disrupted in certain parts of the continental U.S. and Canada during severe weather conditions.
Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could limit our ability to grow or conduct our business.
We may have difficulties in identifying and financing suitable, accretive acquisition opportunities and integrating businesses, assets and personnel.
Our liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.
Our revolving credit facility and term credit facility provide for fluctuating interest rates, which may increase or decrease our interest expense.
Our operations are subject to hazards inherent in the oil and natural gas and energy infrastructure industries, which could expose us to substantial liability and cause us to lose customers and substantial revenue.
We are subject to extensive environmental, health and safety laws, trucking and other regulations that may subject us to increased costs and/or substantial liability.
Our operations in our natural sand proppant services business are dependent on our rights and ability to mine our properties and on our having renewed or received the required permits and approvals from governmental authorities and other third parties.
Changes in tax laws and regulations or adverse outcomes resulting from examination of our tax returns may adversely affect our business, results of operations, financial condition and cash flow.
Cyber incidents or intrusions may result in information theft or other loss, data corruption, operational disruption and/or financial loss.

Risks Inherent to Our Common Stock

Our largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other stockholders.
A significant reduction by our largest stockholder, Wexford of its ownership interests in us could adversely affect us.
Sales of shares of our common stock by our largest stockholders or sales of substantial amounts of our common stock by other stockholders could adversely affect the market price of our common stock.
The corporate opportunity provisions in our certificate of incorporation could enable Wexford or other affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.
We have engaged and expect to continue to engage in transactions with our affiliates, the terms of which and the resolution of any conflicts thereunder may not always be in our or our stockholders’ best interests.
If our operating results do not meet expectations of securities and financial analysts, the price of our common stock could decline.
We may issue preferred stock adversely affecting the voting power or value of our common stock.
Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.
The exclusive forum provisions of our certificate of incorporation could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
The declaration of dividends on our common stock is within the discretion of our board of directors, and there is no guarantee that we will pay any dividends in the future or at levels anticipated by our stockholders.
Our ability to repurchase stock may be limited and no assurance can be given that we will be able to effectuate our stock repurchase program in the future at indicated levels or at all.

Item 1A. Risk Factors

Risks Related to Our Business and the Industries We Serve

Cobra, one of our infrastructure services subsidiaries, was party to service contracts with PREPA. Due to PREPA’s bankruptcy proceedings, PREPAs ability to meet its payment obligations under the contracts is largely dependent upon funding from the FEMA or other sources. In the event that PREPA does not pay amounts owed to us for services performed, our financial condition, results of operations and cash flows would be materially and adversely affected.

    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,
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$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, 2023, PREPA owed us approximately $204.8 million for services performed excluding $197.5 million of interest charged on 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. Since September 30, 2019, we have been pursuing litigation in the U.S. District Court for the District of Puerto Rico and other dispute resolution efforts seeking recovery of the amounts owed to Cobra by PREPA for restoration services in Puerto Rico, which proceedings are discussed in more detail in Note 20—“Commitments and Contingencies—Litigation” included elsewhere in this report. In connection with these efforts, in 2023, an aggregate of $99 million was approved by FEMA for reimbursement to Cobra for services performed by Cobra, of which amount approximately $22.2 million was paid by PREPA to Cobra in 2023. On December 1, 2023, Cobra, as seller, and Mammoth, as guarantor, entered into an assignment agreement (the “Assignment Agreement”) with SPCP Group, LLC (“SPCP Group”), pursuant to which Cobra transferred to SPCP Group all of its rights, title and interest in $54.4 million of outstanding accounts receivable with PREPA and received net proceeds of $46.1 million. See “—Liquidity and Capital Resources—Cobra Assignment Agreement” for additional information. On December 4, 2023, following submission of a joint status report by Cobra and FEMA on December 1, 2023, in which, among other things, PREPA reported that they submitted a request for reimbursement to the Government of Puerto Rico’s Central Recovery and Reconstruction Office (“COR3”) on November 1, 2023 for $82.4 million and is disputing approximately $1.5 million of invoices from Cobra, the Court ordered PREPA to provide a detailed summary of each of their objections to the disputed amounts and directed the parties to report the status of any remaining unpaid approved invoices in connection with the status report due on January 16, 2024. On January 16, 2024, the parties filed a joint status report in which, among other things, PREPA reported that on December 28, 2023, it received a disbursement from COR3 for the amount requested on November 1, 2023 and was in the process of paying approximately $13.4 million in approved but unpaid invoices for reimbursements for services performed by Cobra to SPCP Group, as Cobra’s assignee, which amount was paid by PREPA on January 18, 2024. PREPA, however, also informed the Court that it will withhold the release of any further funds to Cobra approved by FEMA for reimbursement to Cobra due to the municipal and construction excise tax claims against Cobra allegedly aggregating to $70.4 million. Cobra believes it is exempt from the construction excise taxes and strongly disagrees with PREPA’s decision to withhold funds. On January 17, 2024, Cobra filed a Writ of Certiorari requesting the Court of Appeals to reverse the order from the Humacao Superior Court. On February 15, 2024, Cobra’s request was granted by the Court of Appeals and the order instructing PREPA to withhold the $9.0 million payment from Cobra was revoked. The case was remanded to the lower Court for continuation of the proceedings in accordance with the Court of Appeals’ order. The municipality has 15 days to request reconsideration. On January 19, 2024, the Court extended the previously ordered stay in the proceedings through April 5, 2024, and directed the parties to file a joint status report addressing (i) the status of any administrative appeals in connection with the November 2022 and December 2022 determination memoranda regarding the second contract, (ii) the status of any remaining approved, but unpaid invoices, and (iii) whether the parties are actively engaged in mediation to resolve their outstanding issues by March 27, 2024. Subsequent to December 31, 2023, PREPA paid $64.0 million with respect to the outstanding PREPA receivable, of which $9.6 million was paid to Cobra and $54.4 million was paid to SPCP Group, as Cobra’s assignee under the Assignment Agreement, which fully extinguished Cobra’s and Mammoth’s obligations to SPCP Group under the Assignment Agreement, and the Assignment Agreement was terminated.

We believe all amounts charged to PREPA were properly in accordance with the terms of these 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. Further, as noted above, our contracts with PREPA have concluded and we have not obtained, and there can be no assurance that we will be able to obtain, one or more contracts with other customers to replace the level of services that we provided to PREPA.

Our customer base is concentrated and the loss of one or more of our significant customers, or their failure to pay the amounts they owe us, could cause our revenue to decline substantially.

    When a major customer discontinues the use our services, our revenue will decline and our operating results and financial condition will be harmed unless such loss is offset by new business. Our top five customers accounted for approximately 35%, 36% and 35%, respectively, of our revenue for the years ended December 31, 2023, 2022 and 2021. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. In addition, we are subject to credit risk due to the concentration of our customer base. In particular, PREPA owed us approximately $402.3 million (including interest charged on overdue amounts) as of December 31, 2023, as discussed in more detail above. Any nonperformance by our counterparties, including their failure to pay the amounts they owe us on a timely basis or at all, either as a result of changes in financial and economic conditions or otherwise, could have a material adverse impact on our operating results and could adversely affect our liquidity.
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We may experience losses in excess of our recorded reserves for receivables.

We evaluate the collectability of our receivables based on consideration of a customer’s ability to make required payments, payment history, economic events and other factors. Recorded reserves represent our estimate of current expected credit losses on existing receivables and are determined based on historical customer reviews, current financial conditions and reasonable and supportable forecasts. An unexpected change in customer financial condition or future economic uncertainty could result in additional requirements for specific reserves, which could have a material effect on our business, financial condition, results of operations and cash flows.

We cannot predict the impact of the ongoing war in Ukraine and the recent Israel-Hamas war on the global economy, energy markets, geopolitical stability, industries in which we operate and our business.

All of our infrastructure, well completion, natural sand proppant, drilling and other services are concentrated in North America. However, the broader consequences of the Russian-Ukrainian conflict, and the Israel-Hamas war may increase volatility in the price and demand for oil and natural gas, which would adversely impact the oilfield services industry, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of these wars’ effect on our business and results of operations as well as on the global economy, energy markets and industries in which we operate.

The outcomes of investigations and litigation relating to our contracts with PREPA may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 is 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 formed Cobra president to custody of the Bureau of Prisons for six months and one day, a term of supervised release of six months and one day 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 criminal litigation, however, it is not possible at this time to determine the potential impacts that the sentencing 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. 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 have cooperated 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.

Opportunities associated with government contracts could lead to increased governmental regulation applicable to us.

    Most government contracts are awarded through a regulated competitive bidding process. If we are successful in being awarded government contracts, significant costs could be incurred by us before any revenues were realized from these contracts. Government agencies may review a contractor’s performance, cost structure and compliance with applicable laws, regulations and standards. If government agencies determine through these reviews that costs were improperly allocated to specific contracts, they will not reimburse the contractor for those costs or may require the contractor to refund previously reimbursed costs. If government agencies determine that we engaged in improper activity, we may be subject to civil and criminal penalties. Government contracts are also subject to renegotiation of profit and termination by the government prior to the expiration of the term. See the preceding risk factors for information regarding the investigations and legal proceedings relating to our contracts with PREPA.
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Our revolving credit facility and term credit facility impose restrictions on us that may affect our ability to successfully operate our business.

    Our revolving credit facility and term credit facility limit, our ability to take various actions, such as:

incurring additional indebtedness;
paying dividends;
creating certain additional liens on our assets;
entering into sale and leaseback transactions;
making investments;
entering into transactions with affiliates;
making material changes to the type of business we conduct or our business structure;
making guarantees;
entering into hedges;
disposing of assets in excess of certain permitted amounts;
merging or consolidating with other entities; and
selling all or substantially all of our assets.

A portion of our business depends on the oil and natural gas industry and particularly on the level of exploration and production activity within the United States and Canada, and continued volatility in the oil and natural gas markets have impacted, and are likely to continue to impact, our oilfield services and, as a result, our business, financial condition, results of operations, cash flows and stock price.    

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 driven by many factors, including 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 throughout 2022. During 2023, pricing for crude oil and natural gas declined from levels seen in 2022 and 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, conditions in the U.S. oil and gas industry, actions of OPEC+ members, the impact of the ongoing war in Ukraine and the recent Israel-Hamas war 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.

    Many factors over which we have no control affect the supply of and demand for, and our customers’ willingness to explore, develop and produce oil and natural gas, and therefore, influence prices for our products and services, including:

the domestic and foreign supply of and demand for oil and natural gas;
the level of prices, and expectations about future prices, of oil and natural gas;
the level of global oil and natural gas exploration and production;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the expected decline rates of current production;
the price and quantity of foreign imports;
political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia, including the impact of the ongoing war in Ukraine and the recent Israel-Hamas war on the global energy and capital markets and global stability;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
speculative trading in crude oil and natural gas derivative contracts;
the level of consumer product demand;
the discovery rates of new oil and natural gas reserves;
contractions in the credit market;
the strength or weakness of the U.S. dollar;
available pipeline and other transportation capacity;
the levels of oil and natural gas storage;
weather conditions and other natural disasters;
political instability in oil and natural gas producing countries;
domestic and foreign tax policy;
domestic and foreign governmental approvals and regulatory requirements and conditions;
the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;
technical advances affecting energy consumption;
the proximity and capacity of oil and natural gas pipelines and other transportation facilities;
the price and availability of alternative fuels;
the ability of oil and natural gas producers to raise equity capital and debt financing;
global or national health concerns, including the outbreak of pandemic or contagious diseases;
merger and divestiture activity among oil and natural gas producers;
governmental laws, policies, regulations, subsidies, and other actions, including initiatives to promote the use of renewable energy sources; and
overall domestic and global economic conditions.
 
    These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Any of the above factors could impact the level of oil and natural gas exploration and production activity and could ultimately have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, future weakness in commodity prices could impact our business going forward, and we could encounter difficulties such as an inability to access needed capital on attractive terms or at all, recognizing asset impairment charges, an inability to meet financial ratios contained in our debt agreements, a need to reduce our capital spending and other similar impacts.

The cyclicality of the oil and natural gas industry may cause our operating results to fluctuate.

    We derive a portion of our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We have, and may in the future, experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, prolonged low commodity prices experienced by the oil and natural gas industry during the first half of 2020, combined with the ongoing COVID-19 pandemic, adverse changes in demand for our services and volatility in the capital and credit markets, caused many exploration and production companies to reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (e.g., an hour, a day, a week) for the actual period of time the service is provided to our customers. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market prices and utilization, with resulting volatility in our revenues.

If oil prices or natural gas prices decline, the demand for our oil and natural gas services could be adversely affected.

    The demand for our oil and natural gas services is primarily determined by current and anticipated oil and natural gas prices and the related general production spending and level of drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and may cause lower rates and lower utilization of our well service equipment.

    Any future decline in oil and gas prices could materially affect the demand for our services. Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile in the years to come. During 2023, West Texas Intermediate posted prices ranged from $66.74 to $93.68 per barrel and the New York Mercantile Exchange natural
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gas futures prices ranged from $1.99 to $4.48 per MMBtu. If the prices of oil and natural gas decline from current levels, our operations, financial condition and level of expenditures may be materially and adversely affected.

Failure to effectively and timely address the energy transition to a lower carbon footprint could adversely affect our oil and gas business.

Our long-term success depends on our ability to effectively address the energy transition to a lower carbon footprint, which will require adapting our portfolio of oilfield services to potentially changing or more burdensome government requirements and customer preferences. If the energy industry transition changes faster than anticipated or in a manner that we do not anticipate, demand for oilfield services could be adversely affected. Furthermore, if we fail or are perceived to not effectively implement an energy transition strategy, comply with new and evolving regulatory requirements on climate change, or if investors or financial institutions shift funding away from companies in fossil fuel related industries, our business, access to capital and the market for our securities could be negatively impacted. Investor and regulatory focus on environmental, social and governance (“ESG”) matters continues to increase. In addition to climate change, there is increasing attention on topics such as diversity and inclusion, human rights, and human and natural capital, in companies’ own operations as well as their supply chains. In addition, perspectives on the efficacy of ESG considerations continue to evolve, and we cannot currently predict how regulators’, investors’ and other stakeholders’ views on ESG matters may affect the regulatory and investment landscape and affect our business, financial condition, and results of operations. In addition, our inability to timely address these new and evolving regulatory requirements or pressures may result in regulatory enforcement actions or shareholder litigation and otherwise damage our reputation.

In March 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks and other information. To the extent this rule is finalized as proposed, we and/or our customers could incur increased costs related to the assessment and disclosure of climate-related information. Enhanced climate disclosure requirements could also accelerate any trend by certain stakeholders and capital providers to restrict or seek more stringent conditions with respect to their financing of certain carbon intensive sectors.

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect us. For example, shareholder activism has recently been increasing in our industry, and shareholders may attempt to effect changes to our business or governance to deal with climate change-related issues, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise, which may result in significant management distraction and potentially significant expense. Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages. Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions to our business, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and cash flow.

The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and could impose new costs on our operations.

In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. For example, the Infrastructure Investment and Jobs Act and the IRA contain billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration, amongst other provisions. Also, the EPA has proposed ambitious rules to reduce harmful air pollutant emissions, including greenhouse gases, from light-, medium-, and heavy-duty vehicles beginning in model year 2027. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge, which will be phased-in starting in 2024. The IRA could accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives, which could decrease demand for our services related to the oil and natural gas industry.

Deterioration of the commodity price environment can negatively impact oil and natural gas exploration and production companies and, in some cases, impair their ability to timely pay for products or services provided or result in their insolvency or bankruptcy, any of which exposes us to credit risk of our oil and natural gas exploration and production customers.

    In certain economic and commodity price environments, we may experience increased difficulties, delays or failures in collecting outstanding receivables from our customers, due to, among other reasons, a reduction in their cash flow from
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operations, their inability to access the credit markets and, in certain cases, their insolvencies. Such increases in collection issues could have a material adverse effect on our business, results of operations, cash flows and financial condition. We cannot assure you that the reserves we have established for potential credit losses will be sufficient to meet write-offs of uncollectible receivables or that our losses from such receivables will be consistent with our expectations. To the extent one or more of our key customers commences bankruptcy proceedings, as was the case with Gulfport Energy Corporation, our contracts with these customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could also have a material adverse effect on our business, results of operations, cash flows and financial condition.

Shortages, delays in delivery and interruptions in supply of major components, replacement parts or, other equipment, supplies or materials may adversely affect our pressure pumping business.

    During periods of increased demand for drilling and completion services, such as those in the second half of 2022 and early 2023, the industry has experienced shortages of major components, replacement parts, other equipment, supplies and materials, including, in the case of our pressure pumping operations, replacement parts, engines and other equipment, proppants, acid, gel and water. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply could result in significant delays in delivery of equipment and materials and delay or prevent operations. Interruptions may be caused by, among other reasons:

weather issues, whether short-term such as a hurricane or winter storm, or long-term such as a drought; and
shortage in the number of vendors able or willing to provide the necessary equipment, supplies and materials, including as a result of commitments of vendors to other customers or third parties.
 
    These price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating costs. Severe shortages, delays in delivery and interruptions in supply could limit our ability to construct and operate our pressure pumping fleets and hinder our ability to execute on our business plan, any of which could have a material adverse effect on our business, results of operations, cash flows and financial condition.

Oilfield services equipment, refurbishment and new asset construction projects, as well as the reactivation of oilfield service assets that have been idle for six months or longer, are subject to risks which could cause delays or cost overruns and adversely affect our business, cash flows, results of operations and financial position.

    Oilfield services equipment or assets being upgraded, converted or re-activated following a period of inactivity may experience significant start-up costs and complications and may encounter other operational problems that could result in significant delays, uncompensated downtime, reduced day rates or the cancellation, termination or non-renewal of contracts. In this regard, due to market conditions, we have temporarily shut down certain of our service offerings, including contract land drilling, flowback, cementing, acidizing and crude oil hauling operations as well as certain of our facilities, such as our sand processing plant in Pierce County, Wisconsin. Further, construction and upgrade projects are subject to risks of delay or significant cost overruns inherent in any large construction project from numerous factors, including the following:

shortages of equipment, materials or skilled labor;
unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;
failure of equipment to meet quality and/or performance standards;
financial or operating difficulties of equipment vendors;
unanticipated actual or purported change orders;
inability by us or our customers to obtain required permits or approvals, or to meet applicable regulatory standards in our areas of operations;
unanticipated cost increases between order and delivery;
adverse weather conditions and other events of force majeure;
design or engineering changes; and
work stoppages and other labor disputes.

    The occurrence of any of these events could have a material adverse effect on our business, cash flows, results of operations and financial position.

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Advancements in oilfield service technologies could have a material adverse effect on our business, financial condition, results of operations and cash flows.

    The oilfield services industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As new horizontal and directional drilling, pressure pumping, pressure control and well service technologies develop, we may be placed at a competitive disadvantage, and competitive pressure may force us to implement new technologies at a substantial cost. We may not be able to successfully acquire or use new technologies. Further, our customers are increasingly demanding the services of newer, higher specification drilling rigs. There can be no assurance that we will:

have sufficient capital resources to build new, technologically advanced equipment and other assets;
successfully integrate additional oilfield service equipment and other assets;
effectively manage the growth and increased size of our organization, equipment and other assets;
successfully deploy idle, stacked or additional oilfield service assets;
maintain crews necessary to operate additional drilling rigs or pressure pumping service equipment; or
successfully improve our financial condition, results of operations, business or prospects.

    If we are not successful in building or acquiring new oilfield service equipment and other assets or upgrading our existing rigs and equipment in a timely and cost-effective manner, we could lose market share. New technologies, services or standards could render some of our services, equipment and other assets obsolete, which could have a material adverse impact on our business, cash flows, results of operations and financial condition.

Our business depends upon our ability to obtain specialized equipment and parts from third-party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

    We purchase specialized equipment and parts from third party suppliers. At times during the business cycle, there is a high demand for hydraulic fracturing and other oilfield services and extended lead times to obtain equipment needed to provide these services. Further, there are a limited number of suppliers that manufacture the equipment we use. Should our current suppliers be unable or unwilling to provide the necessary equipment and parts or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, future price increases for this type of equipment and parts could negatively impact our ability to purchase new equipment to update or expand our existing fleet or to timely repair equipment in our existing fleet.

Our failure to receive payment for contract change orders or adequately recover on claims brought by us against customers related to payment terms and costs could materially and adversely affect our financial position, results of operations and cash flows.

    We have in the past brought, and may in the future bring, claims against our customers related to, among other things, the payment terms of our contracts and change orders relating to such contracts. These types of claims can occur due to, among other things, customer-caused delays or changes in project scope, both of which may result in additional costs. In some instances, these claims can be the subject of lengthy legal proceedings, and it is difficult to predict the timing and outcome of such proceedings. Our failure to promptly and adequately recover on these types of claims could have an adverse impact on our financial condition, results of operations and cash flows.

We may not accurately estimate the costs associated with infrastructure services provided under fixed price contracts, which could have an adverse effect on our financial condition, results of operations and cash flows.

We derive a portion of our infrastructure services revenue from fixed-price master service and other service agreements. Under these contracts, we typically set the price of our services on a per unit or aggregate basis and assume the risk that costs associated with our performance may be greater than what we estimated. In addition to master service and other service agreements, we enter into contracts for specific projects or jobs that may require the installation or construction of an entire infrastructure system or specified units within an infrastructure system, which are priced on a per unit basis. Profitability will be reduced if actual costs to complete a project exceed our original estimates. Our profitability is dependent upon our ability to accurately estimate the costs associated with our services and our ability to execute in accordance with our plans. A variety of factors could negatively affect these costs, such as lower than anticipated productivity, conditions at work sites differing materially from those anticipated at the time we bid on the contract and higher than expected costs of materials and labor. These variations, along with other risks inherent in performing fixed price contracts, could cause actual project revenue
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and profits to differ from original estimates, which could result in lower margins than anticipated, or losses, which could reduce our profitability, cash flows and liquidity.

We may be unable to obtain sufficient bonding capacity to support certain service offerings, and the need for performance and surety bonds could reduce availability under our credit facility.

    Some of our infrastructure services contracts require performance and payment bonds. If we are not able to renew or obtain a sufficient level of bonding capacity in the future, we may be precluded from being able to bid for certain contracts or successfully contract with certain customers. In addition, even if we are able to successfully renew or obtain performance or payment bonds, we may be required to post letters of credit in connection with the bonds, which would reduce availability under our credit facility. Furthermore, under standard terms in the surety market, sureties issue bonds on a project-by-project basis and can decline to issue bonds at any time or require the posting of additional collateral as a condition to issuing or renewing any bonds. If we were to experience an interruption or reduction in the availability of bonding capacity as a result of these or any other reasons, we may be unable to compete for or work on projects that require bonding.

The nature of our infrastructure services business exposes us to potential liability for warranty claims and faulty engineering, which may reduce our profitability.

    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.

The timing of new contracts and termination of existing contracts may result in unpredictable fluctuations in our cash flows and financial results.

    A portion of our continental United States-based infrastructure services revenue is derived from project-based work that is awarded through a competitive bid process. It is generally very difficult to predict the timing and geographic distribution of the projects that we will be awarded. The selection of, timing of, or failure to obtain projects, delays in awards of projects, the re-bidding or termination of projects due to budget overruns, cancellations of projects or delays in completion of contracts could result in the under-utilization of our assets, which could lower our overall profitability and reduce our cash flows. Even if we are awarded contracts, we face additional risks that could affect whether, or when, work will begin. This can present difficulty in matching workforce size and equipment location with contract needs. In some cases, we may be required to bear the cost of a ready workforce and equipment that is larger than necessary, which could impact our cash flow, expenses and profitability. If an expected contract award or the related work release is delayed or not received, we could incur substantial costs without receipt of any corresponding revenues. Moreover, construction projects for which our services are contracted may require significant expenditures by us prior to receipt of relevant payments from the customer. Finally, the winding down or
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completion of work on significant projects that were active in previous periods will reduce our revenue and earnings if such significant projects have not been replaced in the current period.

    Many of our contracts may be canceled upon short notice, typically 30 to 90 days, even if we are not in default under the contract, and we may be unsuccessful in replacing our contracts if they are canceled or as they are completed or expire. We could experience a decrease in our revenue, net income and liquidity if contracts are canceled and if we are unable to replace canceled, completed or expired contracts. Certain of our infrastructure services customers assign work to us on a project-by-project basis under MSAs. Under these agreements, our customers often have no obligation to assign a specific amount of work to us. Our operations could decline significantly if the anticipated volume of work is not assigned to us or is canceled. Many of our contracts, including our MSAs, are opened to competitive bid at the expiration of their terms. There can be no assurance that we will be the successful bidder on our existing contracts that come up for re-bid.

Delays and reductions in government appropriations can negatively impact energy infrastructure engineering, design, construction, maintenance and repair projects and may impair the ability of our energy infrastructure customers to timely pay for products or services provided or result in their insolvency or bankruptcy, any of which exposes us to credit risk of our infrastructure customers.

    Many of our infrastructure customers derive funding from federal, state and local bodies. Delayed or reduced appropriations may cancel, curtail or delay projects and may have an adverse effect on our business, results of operations, cash flows and financial condition.

Outcomes of rate cases may impact the capital expenditure budgets of our infrastructure customers and may result in lower demand for our services.

Many of our infrastructure customers are regulated by governing bodies and the prices they charge their customers are decided through a process called a rate case. A rate case is a formal process, conducted by utility regulators, to determine if the utility’s proposed base rates are just and reasonable. The outcome of rate cases may impact the capital expenditure budgets of our infrastructure customers and, in turn, could result in lower demand for our services and may have an adverse effect on our business, results of operations, cash flows and financial condition.

An increase in the prices of certain materials used in our businesses could adversely affect our business, financial condition, results of operation and cash flows.

    We are exposed to market risk of increases in certain commodity prices of materials, such as copper and steel, which are used as components of supplies or materials utilized in some of our infrastructure and pressure pumping businesses. An increase in these materials could increase our operating costs, limit our ability to service our customers’ needs or otherwise materially and adversely affect our business, financial condition, results of operation and cash flows.

Inaccuracies in estimates of volumes and qualities of our sand reserves could result in lower than expected sales and higher than expected production costs.

    Estimates of our sand reserves are by nature imprecise and depend to some extent on statistical inferences drawn from available data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of sand reserves and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:

geological and mining conditions and/or effects from prior mining that may not be fully identified by available data or that may differ from experience;
assumptions concerning future prices of frac sand, operating costs, mining technology improvements, development costs and reclamation costs; and
assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.
 
    Any inaccuracy in the estimates related to our sand reserves could result in lower than expected sales and higher than expected costs. For example, these estimates assume that our revenue and cost structure will remain relatively constant over the life of our reserves. If these assumptions prove to be inaccurate, some or all of our reserves may not be economically mineable, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, our current customer contracts require us to deliver frac sand that meets certain specifications. If the estimates of the
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quality of our sand reserves, including the volumes of the various specifications of those reserves, prove to be inaccurate, we may incur significantly higher excavation costs without corresponding increases in revenues, we may not be able to meet our contractual obligations, or our facilities may have a shorter than expected reserve life, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

As part of our natural sand proppant services business, we rely on third parties for raw materials and transportation, and the suspension or termination of our relationship with one or more of these third parties could adversely affect our business, financial conditions, 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.

Future performance of our natural sand proppant services business will depend on our ability to succeed in competitive markets, and on our ability to appropriately react to potential fluctuations in the demand for and supply of frac sand.

    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.

Demand for our frac sand products could be reduced by changes in well stimulation processes and technologies, as well as changes in governmental regulations and other applicable law.

    As part of our natural sand proppant services business, we mine, process and sell frac sand products to our customers for use in their hydraulic fracturing operations to enhance the recovery rates of hydrocarbons from oil and natural gas wells. A significant shift in demand from frac sand to other proppants, or the development of new processes to replace hydraulic fracturing altogether, could cause a decline in the demand for the frac sand we produce and result in a material adverse effect on our business, financial condition, results of operations and cash flows. Further, federal and state governments and agencies have adopted various laws and regulations or are evaluating proposed legislation and regulations that are focused on the extraction of shale gas or oil using hydraulic fracturing, a process which utilizes proppants such as those that we produce. Future hydraulic fracturing-related legislation or regulations could restrict the ability of our customers to utilize, or increase the cost associated with, hydraulic fracturing, which could reduce demand for our proppants and adversely affect our business, financial condition, results of operations and cash flows. For additional information regarding the regulation of hydraulic fracturing, see Item 1. BusinessRegulation of Hydraulic Fracturing included elsewhere in this annual report.

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We face distribution and logistics challenges in our business.

    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.

Increasing transportation and related costs could have a material adverse effect on our business.

    Because of the relatively low cost of producing frac sand, transportation expenses and related costs, including freight charges, fuel surcharges, transloading fees, switching fees, railcar lease costs, demurrage costs and storage fees, comprise a significant component of the total delivered cost of frac sand sales. The relatively high transportation expenses and related costs tend to favor frac sand producers located in close proximity to their customers. If and when we expand our frac sand production, our need for additional transportation services and transload network access will increase. We contract with truck and rail services to move frac sand from our production facilities to transload sites and our customers, and increased costs under these contracts could adversely affect our results of operations. In addition, we bear the risk of non-delivery under our contracts. A significant increase in transportation service rates, a reduction in the dependability or availability of transportation or transload services, or relocation of our customers’ businesses to areas farther from our plants or transloading facilities could impair our ability to deliver our products economically to our customers and our ability to expand into different markets.

Diminished access to water and inability to secure or maintain necessary permits may adversely affect operations of our frac sand processing plants.

    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.

Similar to our natural sand proppant services, certain of our completion and production services, particularly our hydraulic fracturing services, are substantially dependent on the availability of water. Restrictions on our ability, or our customers’ ability, to obtain water may have an adverse effect on our business, financial condition, results of operations and cash flows.

    Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. In recent years, certain areas in which we operate have experienced drought conditions and competition for water in such areas is growing. As a result, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. For example, in 2021, the Texas Legislature directed the Texas Railroad Commission to adopt rules encouraging fluid oil and gas waste recycling. In October 2023, the Commission announced draft amendments to its water protection rules to, among other things, encourage waste recycling. Our inability, or
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customers’ inability, to obtain water to use in our operations from local sources or to effectively utilize flowback water could have an adverse effect on our business, financial condition, results of operations and cash flows.

The customized nature, and remote location, of the modular camps that we provide and service present unique challenges that could adversely affect our ability to successfully operate our remote accommodations business.

    We rely on a third-party subcontractor to manufacture and install the customized modular units used in our remote accommodations business. These customized units often take a considerable amount of time to manufacture and, once manufactured, often need to be delivered to remote areas that are frequently difficult to access by traditional means of transportation. In the event we are unable to provide these modular units in a timely fashion, we may not be entitled to full, or any, payment therefor under the terms of our contracts with customers. In addition, the remote location of the modular camps often makes it difficult to install and maintain the units, and our failure, on a timely basis, to have such units installed and provide maintenance services could result in our breach of, and non-payment by our customers under, the terms of our customer contracts. Any of these factors could have a material adverse effect on our remote accommodation business and our overall financial condition and results of operations.

Health and food safety issues and food-borne illness concerns could adversely affect our remote accommodations business.

    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.

Development of permanent infrastructure in the Canadian oil sands region or other locations where we locate our remote accommodations could negatively impact our remote accommodations business.

    Our remote accommodations business specializes in providing modular housing and related services for workforces in remote areas which lack the infrastructure typically available in towns and cities. If significant development activity does not return to the Canadian oil sands region or if permanent towns, cities and municipal infrastructure develop in the oil sands region of northern Alberta, Canada or other regions where we locate our modular camps, then demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.

Revenue generated and expenses incurred by our remote accommodation business are denominated in the Canadian dollar and could be negatively impacted by currency fluctuations.

    Our remote accommodation business generates revenue and incurs expenses that are denominated in the Canadian dollar. These transactions could be materially affected by currency fluctuations. Changes in currency exchange rates could adversely affect our combined results of operations or financial position. We also maintain cash balances denominated in the Canadian dollar. At December 31, 2023, we had $2.4 million of cash in Canadian dollars, in Canadian accounts. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

In the course of our business, we may become subject to lawsuits, indemnity or other claims, which could materially and adversely affect our business, results of operations and cash flows.

    In addition to the investigations and legal proceedings referenced in the risk factors above, from time to time, we are subject to various claims, lawsuits and other legal proceedings brought or threatened against us in the course of our business. These actions and proceedings may seek, among other things, compensation for alleged personal injury, workers’ compensation, employment discrimination and other employment-related damages, breach of contract, indemnity claims, property damage and violation of federal or state securities laws. We may also be subject to litigation in the normal course of business involving allegations of violations of the Fair Labor Standards Act and state wage and hour laws.
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    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 20. Commitments and Contingencies to our consolidated financial statements elsewhere in this annual report.

We rely on a few key employees whose absence or loss could adversely affect our business.

    Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of our Chief Executive Officer or Chief Financial Officer could disrupt our operations. We do not have any written employment agreement with either our Chief Executive Officer or our Chief Financial Officer at this time. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.

    The delivery of our products and services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the energy services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited. As a result, competition for experienced energy service personnel is intense, and we face significant challenges in competing for crews and management with large and well established competitors. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Unionization efforts could increase our costs or limit our flexibility.

    Presently, none of our employees work under collective bargaining agreements. Unionization efforts have been made from time to time within our industries, to varying degrees of success. Any such unionization could increase our costs or limit our flexibility.

Our operations may be limited or disrupted in certain parts of the continental U.S. and Canada during severe weather conditions, which could have a material adverse effect on our financial condition and results of operations.

    We provide well completion services and drilling services in the Utica, SCOOP, STACK, Permian Basin, Marcellus, Granite Wash, and Cana Woodford resource plays located in the continental U.S. We provide infrastructure services in the northeastern, southwestern, midwestern and western portions of the United States. We provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers located in Ohio, Oklahoma, Texas, Wisconsin, Kentucky, California, Colorado, Oregon, Indiana and Alberta, Canada. For the years ended December 31, 2023 and 2022, we generated approximately 48% and 45%, respectively, of our revenue from our operations in Ohio, Wisconsin, Minnesota, North Dakota, Pennsylvania, West Virginia and Canada where weather conditions may be severe, particularly during winter and spring months. Repercussions of severe weather conditions may include:

curtailment of services;
weather-related damage to equipment resulting in suspension of operations;
weather-related damage to our facilities;
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inability to deliver equipment and materials to jobsites in accordance with contract schedules; and
loss of productivity.

    Many municipalities, including those in Ohio and Wisconsin, impose bans or other restrictions on the use of roads and highways, which include weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This can limit our access to these jobsites and our ability to service wells in these areas. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs in those regions. Weather conditions may also affect the price of crude oil and natural gas, and related demand for our services. Any of these factors could have a material adverse effect on our financial condition and results of operations.

Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

    Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets and global or national health concerns have contributed to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have in the past precipitated and may in the future precipitate an economic slowdown. Concerns about global economic growth may have a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Public health emergencies and resulting adverse economic conditions have had, and may continue to have, a material adverse effect on our financial condition, results of operations, and cash flows.

Public health emergencies have caused, and could again cause, a significant reduction in global economic activity, significantly weakening demand for oil and gas, and in turn, demand for our products and services. Other effects of public health emergencies have included, and may continue to include, significant volatility and disruption of the global financial markets; adverse revenue and net income effects; disruptions to our operations; customer shutdowns of oil and gas exploration and production; downward revisions to customer budgets; limitations on access to sources of liquidity; supply chain disruptions; employee impacts from illness; and local and regional closures or lockdowns, including temporary closures of our facilities and the facilities of our customers and suppliers. The extent to which our operating and financial results will be and may continue to be affected by public health emergencies will depend on various factors beyond our control, such as the continued severity and duration of the public health emergencies, including any sustained geographic resurgence; the emergence of new variants and strains of a contagious disease or virus; and the success of actions to contain or mitigate the effects of the public health emergency.

A terrorist attack or armed conflict could harm our business.
    
    The occurrence or threat of terrorist attacks in the United States or other countries, anti-terrorist efforts and other armed conflicts involving the United States or other countries, including continued hostilities in the Middle East, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could limit our ability to grow.

    Our capital budget for 2024 is estimated to be $15 million, depending upon industry conditions and our financial results. We fund our capital expenditures primarily with cash generated by operations and borrowings under our revolving credit facility and term loan facility. 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. 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
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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, our actual capital expenditures for 2024 or future years could exceed our capital expenditure budget. In the event our operating or capital expenditure requirements at any time are greater than the amount we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, sale-leaseback transactions, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of achieving, maintaining and improving profitability.

The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

    As a component of our business strategy, we have pursued and, subject to our liquidity needs, intend to continue to pursue selected, accretive acquisitions of complementary assets, businesses and technologies. Acquisitions involve numerous risks, including:

unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including but not limited to environmental liabilities;
difficulties in integrating the operations and assets of the acquired business and the acquired personnel;
limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business, in order to comply with public reporting requirements;
potential losses of key employees and customers of the acquired businesses;
inability to commercially develop acquired technologies;
risks of entering markets in which we have limited prior experience; and
increases in our expenses and working capital requirements.
  
    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.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

    Growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand the scope of our activities, lines of our businesses and our geographic coverage through both organic growth and acquisitions, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, engineers and other professionals in the energy services industry, could have a material adverse effect on our business, financial condition, results of operations and our ability to successfully or timely execute our business plan.

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If our intended expansion of our business is not successful, our financial condition, profitability and results of operations could be adversely affected, and we may not achieve increases in revenue and profitability that we hope to realize.

    A key element of our business strategy involves the expansion of our services, geographic presence and customer base. These aspects of our strategy are subject to numerous risks and uncertainties, including:

an inability to retain or hire experienced crews and other personnel;
a lack of customer demand for the services we intend to provide;
an inability to secure necessary financing, equipment, raw materials (particularly sand and other proppants) or technology to successfully execute our expansion plans;
shortages of water used in our sand processing operations and our hydraulic fracturing operations;
unanticipated delays that could limit or defer the provision of services by us and jeopardize our relationships with existing customers and adversely affect our ability to obtain new customers for such services; and
competition from new and existing services providers.
 
    Encountering any of these or any unforeseen problems in implementing our planned expansion could have a material adverse impact on our business, financial condition, results of operations and cash flows, and could prevent us from achieving the increases in revenues and profitability that we hope to realize.

Our liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.

    Our indebtedness may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:

increasing our vulnerability to general adverse economic and industry conditions;
the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industries;
any failure to comply with the financial or other covenants of our debt, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;
our level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and
our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.
 
Our revolving credit facility and term credit facility provide for fluctuating interest rates, which may increase or decrease our interest expense.

    Our revolving credit facility and term credit facility provide for fluctuating interest rates, primarily based on rates set by the U.S. Federal Reserve. Inflation in the U.S. has been rising at its fastest rate in over 40 years, creating inflationary pressure on the cost of services, equipment and other goods in our industries and other sectors and contributing to labor and materials shortages across the supply-chain. Throughout 2022 and 2023, the Federal Reserve increased its benchmark interest rates eight times for an aggregate increase of 4.75 percentage points and may continue increasing benchmark interest rates in the future.

We have not hedged our interest rate exposure with respect to our floating rate debt. Accordingly, our interest expense for any particular period will fluctuate based on the rates set by the U.S. Federal Reserve and other variable interest rates. To the extent the interest rates applicable to our floating rate debt increase, our interest expense will increase, in which event we may have difficulties making interest payments and funding our other fixed costs, and our available cash flow may be adversely affected.

We may not be able to provide services that meet the specific needs of oil and natural gas exploration and production companies or utilities at competitive prices.

    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,
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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.

    In addition, some exploration and production companies have begun performing hydraulic fracturing and directional drilling on their wells using their own equipment and personnel. Any increase in the development and utilization of in-house fracturing and directional drilling capabilities by our customers could decrease the demand for our oil and natural gas services and have a material adverse impact on our business.

Our operations are subject to hazards inherent in the oil and natural gas and energy infrastructure industries, which could expose us to substantial liability and cause us to lose customers and substantial revenue.

    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.

    Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and the insurance coverage may not be adequate to cover claims that may arise, or we may not be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We are subject to extensive environmental, health and safety laws and regulations that may subject us to substantial liability or require us to take actions that will adversely affect our results of operations.

    Our business is significantly affected by stringent and complex federal, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection and health and safety matters. As part of our business, we handle, transport and dispose of a variety of fluids and substances, including hydraulic fracturing fluids which can contain hydrochloric acid and certain petrochemicals. This activity poses some risks of 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
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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.

Further, in connection with providing our infrastructure services, we have made a substantial investment in construction equipment that utilizes petroleum-based fuel. Any changes in laws requiring us to use equipment that runs on alternative fuels could require a significant investment, which could have a material adverse effect on our results of operations, cash flows and liquidity.

Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.

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.

Our operations in our natural sand proppant services business are dependent on our rights and ability to mine our properties and on our having renewed or received the required permits and approvals from governmental authorities and other third parties.

    We hold numerous governmental, environmental, mining and other permits, water rights and approvals authorizing operations at our production facilities. For our extraction and processing in Wisconsin, the permitting process is subject to federal, state and local authority. For example, at the federal level, a Mine Identification Request must be filed and obtained before mining commences. If wetlands are implicated, a U.S. Army Corps of Engineers wetland permit may be required. At the state level, a series of permits are required related to air quality, wetlands, water quality (waste water and storm water), grading, endangered species and archaeological assessments in addition to other permits depending upon site specific factors and operational detail. At the local level, zoning, building, storm water, erosion control, wellhead protection, road usage and access are all regulated and require permitting to some degree. A non-metallic mining reclamation permit is required. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations.

    Title to, and the area of, mineral properties and water rights may also be disputed. Mineral properties sometimes contain claims or transfer histories that examiners cannot verify. A successful claim that we do not have title to our property or lack appropriate water rights could cause us to lose any rights to explore, develop and extract minerals, without compensation for our prior expenditures relating to such property. Our business may suffer a material adverse effect in the event we have title deficiencies.

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    In some instances, we have received access rights or easements from third parties, which allow for a more efficient operation than would exist without the access or easement. A third party could take action to suspend the access or easement, and any such action could be materially adverse to our business, results of operations, cash flows or financial condition.

Penalties, fines or sanctions that may be imposed by the U.S. Mine Safety and Health Administration could have a material adverse effect on our proppant production and sales business and our overall financial condition, results of operations and cash flows.
    
    The U.S. Mine Safety and Health Administration, or MSHA, has primary regulatory jurisdiction over commercial silica operations, including quarries, surface mines, underground mines, and industrial mineral process facilities. In addition, MSHA representatives perform at least two annual inspections of our production facilities to ensure employee and general site safety. As a result of these and future inspections and alleged violations and potential violations, we and our suppliers could be subject to material fines, penalties or sanctions. Any of our production facilities or our suppliers’ mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our proppant production and sales business and our overall financial condition, results of operations and cash flows.

Increasing trucking regulations may increase our costs and negatively impact our results of operations.

    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.

    Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations.

Conservation measures and technological advances could reduce demand for oil and natural gas and our services.

    Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Changes in tax laws and regulations or adverse outcomes resulting from examination of our tax returns may adversely affect our business, results of operations, financial condition and cash flow.
    We are subject to tax liabilities imposed by multiple jurisdictions, including income taxes, indirect taxes (excise/duty, sales/use and value-added taxes), payroll taxes, franchise taxes, withholding taxes and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future, which could have a material adverse effect on our results of operations, financial condition and cash flows. Additionally, many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.

    Our income tax returns are subject to review and examination by the applicable tax authorities. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for income taxes. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon
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challenge by a tax authority. Although we believe our tax provisions are adequate, the final determination of tax audits and any related disputes could be materially different from our historical income tax provisions and accruals. The results of audits or related disputes could have an adverse effect on our financial statements for the periods for which the applicable final determinations are made.

Losses and liabilities from uninsured or underinsured activities could have a material adverse effect on our financial condition and operations.

    The operational insurance coverage we maintain for our business may not fully insure us against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, any insurance obtained by us may not be adequate to cover any losses or liabilities and this insurance may not continue to be available at all or on terms which are acceptable to us. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our business activities, financial condition and results of operations.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.

    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.

Loss of our information and computer systems could adversely affect our business.

    We are heavily dependent on our information systems and computer-based programs. If our programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, whether due to cyberattack or otherwise, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

We are subject to cyber security risks. Cyber incidents or intrusions may result in information theft, data corruption, operational disruption and/or financial loss.

    Our operations have become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, have been and could continue to be the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our security programs and measures, as well as security programs of our customers, suppliers, or other third parties, may not prevent all intrusions and our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our
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protective measures or to investigate and remediate any vulnerability to cyber incidents. Laws and regulations governing cybersecurity, data privacy, and the unauthorized disclosure of confidential or protected information pose increasingly complex compliance challenges, and failure to comply with these laws could result in penalties and legal liability. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.

Increased regulation by state and federal governments related to cybersecurity protections and disclosures may require additional resources for compliance, and any inability, or perceived inability, to adequately address new requirements could subject us to regulatory enforcement, private litigation, public criticism, disrupt our operations, cause us to lose customers, result in additional costs and legal liability, damage our reputation or otherwise harm our business.

Risks Inherent to Our Common Stock

Our largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other stockholders.

    Wexford, through its affiliate MEH Sub LLC, beneficially owns approximately 47.1% of our outstanding common stock. As a result, Wexford can exercise significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. Further, individuals who serve as our directors are affiliates of Wexford. This concentration of ownership and relationship with Wexford makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. In addition, we have engaged, and expect to continue to engage, in related party transactions involving Wexford, and certain companies they control. The interests of Wexford with respect to matters potentially or actually involving or affecting us, such as services provided, future acquisitions, financings and other corporate opportunities, and attempts to acquire us, may conflict with the interests of our other stockholders. This concentrated ownership will make it impossible for another company to acquire us and for you to receive any related takeover premium for your shares unless these stockholders approve the acquisition.

A significant reduction by Wexford of its ownership interests in us could adversely affect us.

    We believe that Wexford’s substantial ownership interest in us provides it with an economic incentive to assist us to be successful. Wexford is not subject to any obligation to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Wexford sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliates that serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to continue comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price, results of operations and financial condition could be materially adversely affected.

We are required to document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting under Section 404 of the Sarbanes Act of 2002. As we perform the required testing of our internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, or if we or our auditors identify material weaknesses in internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

The corporate opportunity provisions in our certificate of incorporation could enable Wexford or other affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.

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    Subject to the limitations of applicable law, our certificate of incorporation, among other things:

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;
permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and
provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.
 
    These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our common stockholders’ best interests.

    We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. As described elsewhere in this report, including in the notes to our consolidated financial statements, these transactions include, among others, a joint venture, agreements to provide our services and frac sand products to our affiliates and agreements pursuant to which our affiliates provide us with facilities. Each of these entities is either controlled by or affiliated with Wexford, as the case may be, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because Wexford may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, see “—Risks Inherent to Our Common Stock—Our largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other stockholders.”

If the price of our common stock fluctuates significantly, your investment could lose value.

    Although our common stock is listed on The Nasdaq Global Select Market, an active public market for our common stock may not be maintained. If an active public market for our common stock is not maintained, the trading price and liquidity of our common stock will be materially and adversely affected. Without a large float, our common stock is less liquid than the securities of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. The market price for our common stock has fluctuated significantly, ranging from a high of $8.74 per share to a low of $3.41 per share during 2023. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

our quarterly or annual operating results;
changes in our earnings estimates;
investment recommendations by securities analysts following our business or our industries;
additions or departures of key personnel;
changes in the business, earnings estimates or market perceptions of our competitors;
our failure to achieve operating results consistent with securities analysts’ projections;
changes in industry, general market or economic conditions; and
announcements of legislative or regulatory change.
 
    The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industries. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce the price for our common stock.

Wexford beneficially owns a substantial amount of our common stock and may sell such common stock in the public or private markets. Sales of these shares of common stock or sales of substantial amounts of our common stock by other
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stockholders, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock.

    As of December 31, 2023, Wexford beneficially owned 47.1% shares of our common stock. Sales of these shares of common stock or sales of substantial amounts of our common stock by other stockholders, or the perception that such sales may occur, could cause the price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely revise their recommendations regarding our stock or if our operating results do not meet their expectations, the price of our stock could decline.

    The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

    Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

    The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;
limitations on the ability of our stockholders to call a special meeting and act by written consent;
the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;
the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and
the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders. 
 
    These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

Our certificate of incorporation designates courts in the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees.
    
    Our certificate of incorporation provides that, subject to limited exceptions, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for:
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Any derivative action or proceeding brought on our behalf;
Any action asserting a claim of breach of fiduciary duty owed by any of our directors, officers or other employees to us or our stockholders;
Any action asserting a claim against us arising pursuant to any provision of the Delaware General Corporation Law; or
Any other action asserting a claim against us that is governed by the internal affairs doctrine.
 
    In addition, our certificate of incorporation provides that if any action specified above (each is referred to herein as a covered proceeding), is filed in a court other than the specified Delaware courts without the approval of our board of directors (each is referred to herein as a foreign action), the claiming party will be deemed to have consented to (i) the personal jurisdiction of the specified Delaware courts in connection with any action brought in any such courts to enforce the exclusive forum provision described above and (ii) having service of process made upon such claiming party in any such enforcement action by service upon such claiming party’s counsel in the foreign action as agent for such claiming party. These provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits against us and our directors, officers and employees. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the covered proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business and financial condition.

The declaration of dividends on our common stock is within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends in the future or at levels anticipated by our stockholders.
On July 16, 2018, our board of directors initiated a quarterly dividend policy on shares of our common stock payable quarterly beginning with the second quarter of 2018. In July 2019, as a result of oilfield market conditions and other factors, which included the status of collections from PREPA, our board of directors suspended the quarterly cash dividend. The decision to pay dividends is solely within the discretion of, and subject to approval by, our board of directors. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than anticipated, either of which could reduce returns to our stockholders.
Our ability to repurchase stock may be limited and no assurance can be given that we will be able to effectuate our stock repurchase program in the future at indicated levels or at all.
On August 10, 2023, our board of directors approved a stock repurchase program pursuant to which we would be authorized to repurchase up to the lesser of $55 million or 10 million shares of its common stock, subject to the factors discussed below. Following the completion of the refinancing transactions discussed in this report, any stock repurchases under this program may be made opportunistically from time to time in open market or privately negotiated transactions in compliance with Rule 10b-18 under the Securities Act of 1934, as amended, including any 10b5-1 plan, and will be subject to market conditions, applicable legal and contractual restrictions, liquidity requirements and other factors. The repurchase program has no time limit, does not require us to repurchase any specific number of shares and may be suspended from time to time, modified or discontinued by our board of directors at any time. Any common stock repurchased as part of such stock repurchase program will be cancelled and retired. No assurance can be given that we will effectuate stock buybacks in the future, which could materially and adversely affect the market price of our common stock. We have not repurchased any shares of our common stock under the stock repurchase program as of December 31, 2023 or to date.

Item 1B. Unresolved Staff Comments

None.

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MAMMOTH ENERGY SERVICES, INC.


Item 1C. Cybersecurity

Cybersecurity Risk Management and Strategy

We depend on digital technologies to perform many of our services and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. To assess and manage cybersecurity risks impacting our industry and our business, we have implemented and invested in, and will continue to implement and invest in, controls, procedures and protections (including internal and external personnel) that are designed to protect our systems, identify and remediate vulnerabilities in our systems and related infrastructure on a regular basis and monitor and mitigate the risk of data loss and other cybersecurity threats. As part of our cybersecurity risk management program, we have a designated in-house team principally responsible for managing cybersecurity risk assessment processes, security controls and response to cybersecurity incidents or intrusions. We have also engaged third-party consultants to conduct penetration testing and risk assessments.

Our cybersecurity risk management program is integrated into our overall enterprise risk management program, using common methodologies, reporting channels and governance processes that apply to other risks managed by our organization, including operational, financial and strategic risks, as well as applicable legal and regulatory risks.

Our cybersecurity governance program is informed by the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework and measured by the Maturity and Risk Assessment Ratings associated with the NIST Cybersecurity Framework and the Capability Maturity Model Integration. In addition, our cybersecurity risk management program includes processes to assess cybersecurity risks related to third-party vendors and suppliers.

Cybersecurity Governance

Our cybersecurity team consists of in-house cybersecurity professionals and external threat analysts, consultants and service providers. Our in-house professionals and external threat analysts possess various cybersecurity certifications, including Security +, Network +, A + and Server + certifications.

Our internal cybersecurity governance program is led by Mammoth’s Director of Information Technology, with support from the internal information technology department, who reports to our Chief Financial Officer. Our Director of
Information Technology has over six years of technological leadership experience along with an extensive background in computer support and application support. The Director of Information Technology and her team are responsible for leading cybersecurity strategy, policy, standards, architecture, and processes within our organization. In addition, our cybersecurity incident response team is responsible for responding to cybersecurity incidents. This team continuously identifies potential cyber vulnerabilities and opportunities for improvement, including yearly security training for all employees. This team also continuously evaluates and implements technological enhancements as part of our cybersecurity systems. Progress and developments in our cybersecurity governance program are regularly communicated to our executive team. Our board of directors, as part of its oversight process, receives quarterly updates on the status of our cybersecurity governance program, including as related to new or developing initiatives and any security incidents that have occurred.

Risks from cybersecurity threats, incidents or intrusions have not thus far materially affected, and are not currently anticipated to materially affect, our Company, including our business strategy, results of operations or financial condition. See, however, Item 1.A, Risk Factors—“We are subject to cyber security risks. Cyber incidents or intrusions may result in information theft, data corruption, operational disruption and/or financial loss” for additional information regarding cybersecurity risks we face and their potential impact on our business strategy, results of operations and financial condition.

In addition, our internal audit function, in conjunction with third-party experts, plays a key role in reviewing and assessing our cybersecurity technologies, controls and procedures. Our security programs and measures may not prevent all incidents or intrusions and our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cybersecurity risks continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents or intrusions. Laws and regulations governing cybersecurity, data privacy, and the unauthorized disclosure of confidential or protected information pose increasingly complex compliance challenges, and failure to comply with these laws could result in penalties and legal liability. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.

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Item 2. Properties

Overview of Sand Properties and Operations

    Information concerning our mining properties in this annual report has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires us to disclose our mineral resources, in addition to our mineral reserves, as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties.

As used in this annual report, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. You are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the SEC. You are further cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value.

The information that follows is derived, in part, from the technical report summary prepared by John T. Boyd Company in February 2022, our third-party mining and geological consultant and an external qualified person, (“John T. Boyd”), in compliance with Item 601(b)(96) and subpart 1300 of Regulation S-K. As of December 31, 2023, in the opinion of John T. Boyd, there were no material changes in mineral (frac sand) resources/mineral (frac sand) reserves, material assumptions or other technical information from those reported in the February 2022 technical report. As a result, we are relying on the February 2022 technical report, as updated by John T. Boyd for immaterial changes in our reserves/resources as of December 31, 2023. Portions of the following information are based on assumptions, qualifications and procedures that are summarized here and are described in more detail in the technical report. Reference should be made to the full text of the technical report summary, incorporated herein by reference and made a part of this annual report.

    Our natural sand proppant business mines, processes and sells high quality Northern White silica, a key input for the hydraulic fracturing of oil and gas wells, which we refer to as frac sand. Northern White frac sand deposits are generally located in the north-central portion of the United States (predominantly in Minnesota, Wisconsin and Illinois, with lesser amounts in Arkansas and Iowa). Northern White frac sand is found in poorly cemented Cambrian and Ordovician sandstones and in unconsolidated alluvial deposits locally derived from these sandstones. All of our frac sand facilities are located in Wisconsin, with our Taylor facilities located in Jackson County, our Piranha facilities located in Barron County and our Muskie facilities located in Pierce County.

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Figure 1.1.jpg

Our frac sand facilities consist of three dry plants with a total permitted capacity of 5.7 million tons of sand per year, and two wet plants, with a total permitted capacity of 8.7 million tons of sand per year, that supply two of the dry plants with Northern White silica sand, which we believe is some of the highest quality raw frac sand available. Our Muskie plant in Pierce County, Wisconsin is currently idled. Our frac sand facilities operate seasonally from March or April through October or November depending on both weather and material demand.

    We produce predominantly 20/40-mesh, 30/50-mesh and 40/70-mesh frac sand. The production of our frac sand consists of three basic processes: mining, wet plant operations and dry plant operations. All mining activities take place in an open pit environment, whereby we remove the topsoil, which is set aside, and then remove other non-economic minerals, or “overburden,” to expose the sand deposits. A third-party contractor then “bumps” the sand using explosives on the mine face,
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which causes the sand to fall into the pit, where it is then carried by truck or conveyor to the wet plant operations. At our wet plants, the mined sand goes through a series of processes designed to separate the sand from unusable materials. The resulting wet sand is then conveyed to a wet sand stockpile where most of the water is allowed to drain into our on-site recycling facility, while the remaining fine grains and materials, if any, are separated through a series of settlement ponds. We reuse the water that does not evaporate in our wet process. Wet sand from our stockpile is then conveyed or trucked to our dry plants where the sand is dried, screened into specific mesh categories and stored in silos. From the silos, we load sand directly into railcars or trucks, which we then ship to one of our transloading facilities or directly to our customers. For information regarding our transloading facilities and shipping capabilities, see “Item 1. Business-Our Services-Natural Sand Proppant Services.”

    Our Wisconsin dry plants are enclosed facilities capable of running year-round, regardless of the weather. Under normal market conditions, we typically operate our plants with work crews of ten to 15 employees. These crews typically work 40-hour weeks, with shifts between eight and twelve hours, depending on the employee’s function. Because raw sand cannot be wet-processed during extremely cold temperatures, we typically mine and wet-process sand eight months out of the year at our Taylor and Piranha locations. Our Muskie location has an indoor wash facility, which is capable of being run year-round.

    Our Taylor and Piranha mines are located in western Wisconsin, near an estimated combined population of over 350,000 people. Both sites are accessible via a well-developed network of primary and secondary roads, which offer direct access to the mines and processing facilities and are open year-round. Our Taylor facilities have access to the Canadian National rail network, while our Piranha facilities have access to the Union Pacific rail network. Both operations have readily available access to requisite electrical power, natural gas and water. Each of our facilities undergoes regular maintenance to minimize unscheduled downtime and to ensure that the quality of our frac sand meets API standards and our customers’ specifications. In addition, we make capital investments in our facilities as required to support customer demand, and our performance goals.

    The following table provides information regarding our aggregate sand mined for December 31, 2023, 2022 and 2021:

Total Sand Mined
 (Thousands of Tons)
As of December 31,
202320222021
Plant Location
Taylor in Jackson County, Wisconsin608 630 567 
Piranha in Barron County, Wisconsin696 766 320 
Total1,304 1,396 887 

Mineral Resources and Reserves

    The quantity and nature of our mineral resources and reserves are estimated by John T. Boyd, while we internally track depletion rate on an interim basis. Estimates of frac sand reserves for the Taylor mine and Piranha mine were derived contemporaneously with estimates of frac sand resources. To derive an estimate of saleable product tons (proven and probable frac sand reserves), the following modifying factors were applied to the in-place measured and indicated frac sand resources underlying the respective mine plan areas:

A 90% mining recovery factor, which assumes that 10% of the mineable (in-place) frac sand resource will not be recovered during mining for various reasons. Applying this recovery factor to the in-place resource results in the estimated sand tonnage that will be delivered to the wet process plant.
An overall 79% processing recovery. This recovery factor accounts for losses in the wet and dry plants. This recovery factor accounts for removal of out-sized (i.e., larger than 20-mesh and smaller than 100-mesh) sand and losses in the wet and dry processing plants due to minor inefficiencies.

We do not have any reportable frac sand resources excluding those converted to frac sand proven reserves for the Taylor and Piranha mines. Any frac sand within the defined boundaries of the Taylor and Piranha mines which is not reported as frac sand reserves are not considered to have potential economic viability. Therefore, they are not reportable as frac sand resources. Further, as we do not own any mineral rights for the Muskie properties, but, rather, own only the surface rights to the processing plants, we do not (and do not expect to ever) report any reserves attributable to our Muskie property. John T. Boyd updates our reserve estimates annually, making necessary adjustments for operations at each location during the year and
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additions or surveying, drill core analysis and other tests to confirm the quantity and quality of the reserves. The following table presents our estimated frac sand reserves for the Taylor and Piranha mines as of December 31, 2023 (amounts in thousands):

MineReserves Category
Total Reserves(1)(2)
TaylorProven23,191 
PiranhaProven36,706 
Total59,897 
1.Pricing data based on the weighted average projected sales price for sand of $19.73 per ton for Taylors operations and $18.59 for Piranhas operations.
2.John T. Boyd has determined that all reportable mineral resources for the Taylor and Piranha mines are categorized as proven reserves as the areas are well explored and exhibit acceptable drill hole data spacing to be classified as measured resources.

We categorize our sand properties in accordance with the SEC definition in Item 1300 of Regulation S-K. Our mineral resources are concentration or occurrence of material of economic interest in or on the Earth’s crust in such form, grade or quality and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled. Our sand reserves are our estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of the qualified person, can be the basis of an economically viable project. More specifically, they are the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.

John T. Boyd updates our reserve estimates annually, making necessary adjustments for operations at each location during the year and additions or surveying, drill core analysis and other tests to confirm the quantity and quality of the reserves. To opine as to the economic viability of our reserves, John T. Boyd reviewed our financial cost and revenue per ton data at the time of the proven reserve determination. Our 2023 average monthly sales prices ranged from approximately $20 to $32 per ton free on board mine. Based on its review of our cost structure and its extensive experience with similar operations, John T. Boyd concluded that it is reasonable to assume that we will operate under a similar cost structure over the remaining life of our reserves. Based on these assumptions, and taking into account possible cost increases associated with a maturing mine, John T. Boyd concluded that our current operating margins are sufficient to expect continued profitability throughout the life of our reserves.

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.

Surface and Mineral Rights

For each of our Taylor and Piranha frac sand facilities, we own surface and mineral rights. For our Muskie sand facility, we own surface rights.

Individual Properties

Taylor. Our Taylor operation is located less than one mile northwest of the town of Taylor, in Jackson County, Wisconsin and encompasses a total of approximately 393 acres. Approximately 148 acres of frac sand resources remain on this
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property. We own in fee numerous land parcels which comprise the processing plant site, mineral resource areas and rail loadout facility. Our rail loadout facility, located in Trempealeau County, Wisconsin, is approximately two miles southwest of the mine and processing facility. Our Taylor operation commenced mining operations in 2012. We acquired the Taylor operation in June 2017 when we acquired Sturgeon Acquisitions, LLC. The total net book value of the Taylor operation’s real property and fixed assets as of December 31, 2023, was $24.2 million.

Figure 6.2.jpg

The site contains a mine with 23.2 million tons of proven recoverable proppant sand reserves as of December 31, 2023, based on estimates prepared by John T. Boyd. Our Taylor wet plant can currently process up to 2.6 million tons of wet frac sand per year. Our Taylor dry plant is adjacent to our Taylor wet plant and wash facilities. As of December 31, 2023, the dry plant had a rated production capacity of 2.2 million tons per year. Our current air permit allows us to produce up to 2.2 million tons per year of finished product. The Taylor facility includes a 150 ton per hour natural gas fluid bed dryer and a 100 ton per hour natural gas fluid bed dryer as well as nine high-capacity screeners that are capable of producing 2.2 million tons of frac sand per year. During the year ended December 31, 2023, our Taylor facility produced 0.6 million tons of finished sand product. Our finished product is transported via truck to our transloading facility with rail access.

We estimate an overall product yield (after mining and processing losses) of approximately 66% for the Taylor mine. John T. Boyd utilized post December 31, 2017 production data we provided, along with the John T. Boyd January 2019 Report amending the resource tons as of December 31, 2017, to reconcile the amended estimate from the December 31, 2017 estimate to December 31, 2023. The following table presents a summary of our mineral reserves for the Taylor mine as of December 31, 2023, together with a comparison to the reserves as of the end of the preceding fiscal year and an explanation of any material changes.


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Taylor Mine – Summary of Reserves(1)(2) (Thousands of Tons)

Amount as of
Reserves CategoryDecember 31, 2023December 31, 2022Change% Change
Proven23,191 23,822 (631)(3)%
1.Pricing data based on the weighted average projected sales price for sand of $19.73 per ton.
2.John T. Boyd has determined that all reportable mineral resources for the Taylor mine are categorized as proven reserves as the area is well explored and exhibit acceptable drill hole data spacing to be classified as a measured resource.

The decrease from 2022 to 2023 is primarily attributed to depletion by mining 0.6 million tons of sand.

Piranha. Our Piranha operation is located approximately five miles northwest of the town of New Auburn, in Baron County, Wisconsin and encompasses a total of approximately 608 acres. The current estimated mineable area is approximately 313 acres, or 52% of the total property, after observing setbacks, right of ways, processing areas and other non-mining acreage. We own 100% of the surface and mineral rights. Our dry plant and loadout is also located in Baron County and is approximately one mile east of the mine and wet processing facility. We acquired the Piranha operation on May 26, 2017 from Chieftain Sand and Proppant LLC (Chieftain). Under Chieftain, the property commenced mining operations in August 2012. In January 2018, we purchased the Conoboy tract, which is adjacent to a tract of land previously mined by Chieftain. The total net book value of the Piranha operation’s real property and fixed assets as of December 31, 2023 was $13.4 million.

Figure 6.2.jpg

The site contains 36.7 million tons of proven recoverable proppant sand reserves as of December 31, 2023, based on estimates prepared by John T. Boyd. Our Piranha wet plant, which is adjacent to the mine, can process up to 4.7 million tons of wet sand per year and is located two miles from our Piranha dry plant, to which we have year-round trucking access. As of December 31, 2023, the dry plant facility had a rated production capacity of 2.6 million tons per year. Our current air permit allows us to produce up to 3.5 million tons per year of finished product. Our Piranha facility includes a 150 ton per hour natural
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gas fired fluid bed dryer and a 200 ton per hour natural gas fluid bed dryer as well as seven high-capacity screeners capable of producing 2.6 million tons of frac sand per year. During the year ended December 31, 2023, our Piranha facility produced 0.7 million tons of sand. Our finished product is loaded directly into railcars. Our Piranha facility is capable of storing up to 400 railcars.

We estimate an overall product yield (after mining and processing losses) of approximately 71% for the Piranha mine. John T. Boyd utilized post March 31, 2017 production data we provided, in conjunction with other data, to reconcile the estimate from the March 31, 2017 volumetric estimate to December 31, 2023. The following table presents a summary of our mineral reserves for the Piranha mine as of December 31, 2023, together with a comparison to the reserves as of the end of the preceding fiscal year and an explanation of any material changes.

Piranha Mine – Summary of Reserves(1)(2) (Thousands of Tons)

Amount as of
Reserves CategoryDecember 31, 2023December 31, 2022Change% Change
Proven36,706 37,351 (645)(2)%
1.Pricing data based on the weighted average projected sales price for sand of $18.59 per ton.
2.John T. Boyd has determined that all reportable mineral resources for the Piranha mine are categorized as proven reserves as the area is well explored and exhibit acceptable drill hole data spacing to be classified as a measured resource.

The decrease from 2022 to 2023 is primarily attributed to depletion by mining 0.7 million tons of sand.

Muskie. Our Muskie facilities are located in Plum City, Wisconsin and encompass a total of approximately 40 acres. Although this plant is currently idled, our Muskie wet plant can process up to 1.3 million tons of wet sand per year. The site includes an indoor facility capable of washing sand year-round and an enclosed dry plant facility that has a rated production capacity of 2,400 tons per day. Our current air permit allows us to produce up to 0.9 million tons per year of finished product. The facility has a 100 ton per hour natural gas fired fluid bed dryer as well as six high-capacity screeners that are capable of producing 0.9 million tons per year. As a result of adverse market conditions, production at our Muskie facility has been temporarily idled since September 2018. When operating, our finished product is transported via truck to a third-party facility with rail access. The site does not contain any proppant sand reserves. Our Muskie facility commenced operations in 2012. Muskie was contributed to Mammoth in November 2014. The total net book value of the Muskie operation’s real property and fixed assets as of December 31, 2023, was $5.2 million.

Headquarters

Our corporate headquarters are located at 14201 Caliber Drive, Suite 300, Oklahoma City, Oklahoma 73134. We currently own 12 properties, four located in Wisconsin, four located in Ohio, three located in Texas and one located in Oklahoma, which are used for field offices, yards, production plants or housing. In addition to our headquarters, we also lease 24 properties that are used for field offices, yards or transloading facilities for frac sand. We believe that our facilities are adequate for our current operations.

Item 3. Legal Proceedings

    We are a party to, or the subject of, certain investigations and legal proceedings discussed elsewhere in this annual report. For a description of such investigations and legal proceedings, see Note 20. Commitments and Contingencies to our consolidated financial statements included elsewhere in this annual report and Item 1A. “Risk Factors—Risks Related to Our Business and the Industries We Serve—Cobra, one of our infrastructure services subsidiaries, was party to service contracts with PREPA. Due to PREPA’s bankruptcy proceedings, PREPAs ability to meet its payment obligations under the contracts is largely dependent upon funding from the FEMA or other sources. In the event that PREPA does not pay amounts owed to us for services performed, our financial condition, results of operations and cash flows would be materially and adversely affected.” and “—The outcomes of investigations and litigation relating to our contracts with PREPA may have a material adverse effect on our financial condition, results of operations and cash flows.”

In addition, due to the nature of our business, we are, from time to time, also involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes.

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Except as described in Note 20, Item 1A referenced above and elsewhere in this annual report, in the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our business, financial condition, results of operations or cash flows.

Item 4. Mine Safety Disclosures

    Our operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. Our failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on our business and financial condition or otherwise impose significant restrictions on our ability to conduct mineral extraction and processing operations. Following passage of The Mine Improvement and New Emergency Response Act of 2006, MSHA significantly increased the numbers of citations and orders charged against mining operations. The dollar penalties assessed for citations issued has also increased in recent years. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Report.
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PART II. OTHER INFORMATION

Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information and Holders of Record

    Our common stock is traded on the Nasdaq Global Select Market under the symbol “TUSK.” As of the close of business on February 28, 2024, there were 83 holders of record of our common stock. The number of holders of record of our common stock is not representative of the number of beneficial holders because many of the shares are held by depositories, brokers or nominees.

Unregistered Sales of Equity Securities    
    None.

Issuer Purchases of Equity Securities

    On August 10, 2023, our board of directors approved a stock repurchase program pursuant to which we would be authorized to repurchase up to the lesser of $55 million or 10 million shares of its common stock, subject to the factors discussed below. Following the completion of the refinancing transactions discussed in this report, any stock repurchases under this program may be made opportunistically from time to time in open market or privately negotiated transactions in compliance with Rule 10b-18 under the Securities Act of 1934, as amended, including any 10b5-1 plan, and will be subject to market conditions, applicable legal and contractual restrictions, liquidity requirements and other factors. The repurchase program has no time limit, does not require us to repurchase any specific number of shares and may be suspended from time to time, modified or discontinued by our board of directors at any time. Any common stock repurchased as part of such stock repurchase program will be cancelled and retired. We have not repurchased any shares of our common stock under the stock repurchase program as of December 31, 2023 or to date. See also Item 1.A. “Risk Factors--Our ability to repurchase stock may be limited and no assurance can be given that we will be able to effectuate our stock repurchase program in the future at indicated levels or at all.”

Dividends

    On July 16, 2018, we initiated a quarterly dividend policy and declared our first quarterly cash dividend. In July 2019, as a result of oilfield market conditions and other factors, which included the status of collections from PREPA, our board of directors suspended the quarterly cash dividend. 
    
    Our board of directors’ determination with respect to any future dividends will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination. Based on its evaluation of these factors, the board of directors may determine not to declare a dividend, or declare dividends at rates that are less than currently anticipated.


Item 6. [Reserved]
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. “Risk Factors” and the section entitled “Forward-Looking Statements” appearing elsewhere in this annual report.
Overview
    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.

    The growth of our industrial businesses is ongoing. We offer infrastructure engineering services focused on the transmission and distribution industry and also have equipment manufacturing operations and offer fiber optic services. Our equipment manufacturing operations provide us with the ability to repair much of our existing equipment in-house, as well as the option to manufacture certain new equipment we may need in the future. Our fiber optic services include the installation of both aerial and buried fiber. We are continuing to explore other opportunities to expand our industrial business lines.

Our revenues, operating (loss) income and identifiable assets are primarily attributable to four reportable segments: well completion services; infrastructure services; natural sand proppant services; and drilling services. Prior to 2023, we included Bison Trucking LLC, or Bison Trucking, in our drilling segment. Based on our assessment of FASB ASC 280, Segment Reporting, guidance at December 31, 2023, we changed our presentation in 2023 to move Bison Trucking to the reconciling column titled “All Other”. The results for the year ended December 31, 2022 have been retroactively adjusted to reflect this change.

Well Completion Services Segment
Stingray Pressure Pumping LLC—March 2012
Silverback Energy LLC—November 2012
Redback Pump Down Services LLC—January 2015
Mr. Inspections LLC—January 2015
Mammoth Equipment Leasing LLC—November 2016
Bison Sand Logistics LLC—January 2018
Aquahawk Energy LLC—June 2018

Infrastructure Services Segment
Cobra Acquisitions LLC, or Cobra—January 2017
Lion Power Services LLC, formerly Cobra Energy LLC—January 2017
Higher Power Electrical LLC—April 2017
5 Star Electric LLC—July 2017
Python Equipment LLC—December 2018
Aquawolf LLC—September 2019
Falcon Fiber Solutions LLC—May 2021

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Natural Sand Proppant Services Segment
Muskie Proppant LLC—September 2011
Barracuda Logistics LLC—October 2014
Piranha Proppant LLC—May 2017
Sturgeon Acquisitions LLC—June 2017
Taylor Frac, LLC—June 2017
Taylor Real Estate Investments, LLC—June 2017
South River Road, LLC—June 2017

Drilling Services Segment
Bison Drilling and Field Services, LLC—November 2010
Panther Drilling Systems LLC—December 2012

Other
Great White Sand Tiger Lodging Ltd.—October 2007
Redback Energy Services, LLC—October 2011
Redback Coil Tubing, LLC—May 2012
Bison Trucking—August 2013
Anaconda Rentals LLC, formerly White Wing Tubular Services LLC—September 2014
WTL Oil LLC, or WTL, formerly Silverback—June 2016
Mammoth Energy Services Inc.—June 2016
Mammoth Energy Partners, LLC—October 2016
Mako Acquisitions LLC—March 2017
Stingray Energy Services LLC, or Stingray Energy Services—June 2017
Stingray Cementing LLC—June 2017
Tiger Shark Logistics LLC—October 2017
Cobra Aviation Services LLC—January 2018
Black Mamba Energy LLC—March 2018
Stingray Cementing and Acidizing LLC, formerly RTS Energy Services LLC—June 2018
Ivory Freight Solutions LLC—July 2018
IFX Transport LLC—December 2018
Air Rescue Systems LLC (“ARS”)—December 2018 through July 13, 2023
Leopard Aviation LLC—April 2019
Anaconda Manufacturing LLC—September 2019

On July 13, 2023, the Company sold its equity interests in ARS. Activity for ARS through the date of sale is included in the accompanying results of operations.

2023 Financial Overview and Highlights

Net loss of $3.2 million, or $0.07 per diluted share, for the year ended December 31, 2023 as compared to net loss of $0.6 million, or $0.01 per diluted share, for the year ended December 31, 2022.

Adjusted EBITDA of $71.0 million for the year ended December 31, 2023 as compared to $86.1 million for the year ended December 31, 2022. See “Non-GAAP Financial Measures” below for a reconciliation of net loss to Adjusted EBITDA.

Reduced debt by $40.7 million from $83.5 million as of December 31, 2022 to $42.8 million as of December 31, 2023.

Net cash flow provided by operating activities was $31.4 million for the year ended December 31, 2023 as compared to $15.3 million for the year ended December 31, 2022.

On August 10, 2023, our board of directors approved a stock repurchase program pursuant to which we are authorized to repurchase up to the lesser of $55 million or 10 million shares of our common stock, subject to liquidity considerations and other factors. No shares have yet been repurchased under this stock repurchase program. See “—Repurchase Program Authorization” below.

On October 16, 2023, we entered into the new revolving credit facility and the new term credit facility, in each case maturing on the specified date in 2028, subject to the terms and conditions thereof, which facilities refinanced in full
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our indebtedness outstanding under the then existing credit facility. See “—Liquidity and Capital Resources—New Revolving Credit Facility and New Term Credit Facility” for additional information regarding the new revolving credit facility and the new term loan.

On December 1, 2023, Cobra, as seller, and Mammoth, as guarantor, entered into an assignment agreement (the “Assignment Agreement”) with SPCP Group, LLC (“SPCP Group”). Under the terms and conditions of the Assignment Agreement, Cobra transferred to SPCP Group all of its rights, title and interest in $54.4 million of outstanding accounts receivable with PREPA and received net proceeds of $46.1 million. Subsequent to December 31, 2023, PREPA paid $64.0 million with respect to the outstanding PREPA receivable. Of the $64.0 million, $54.4 million was paid to SPCP Group, as Cobra’s assignee under the Assignment Agreement, which fully extinguished Cobra’s and Mammoth’s obligations to SPCP Group, and the Assignment Agreement was terminated. The remaining $9.6 million was paid to Cobra.

Overview of Our Industries

Oil and Natural Gas Industry    

     The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and related services and products budgets. The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity, storage capacity, shortages of equipment and materials and other conditions and factors that are beyond our control.

    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 driven by many factors, including 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. We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services during 2022. Throughout 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion activities for our customers, in particular, in the Utica and Marcellus Shale natural gas plays, and, as a result, reduced demand for our well completion services. These factors have continued into the first quarter of 2024. Despite this near-term softness, however, we are seeing indications that activity levels will begin to ramp back up in mid-2024, creating the opportunity to reactivate additional fleets, if appropriate. The ongoing war in Ukraine and the recent Israel-Hamas war, however, could continue to have an adverse impact on the global energy markets and volatility of commodity prices, which could further adversely impact demand for our well completion services.

In response to market conditions, we temporarily shut down our cementing and acidizing operations and flowback operations beginning in July 2019, our contract drilling operations beginning in December 2019, our rig hauling operations beginning in April 2020, our coil tubing, pressure control and full service transportation operations beginning in July 2020 and our crude oil hauling operations beginning in July 2021. We continue to monitor the market to determine if and when we can recommence these services.

Natural Sand Proppant Industry
We experienced a significant decline in demand of our sand proppant in the second half of 2019 and throughout 2020 as a result of completion activity falling due to lower oil demand and pricing, increased capital discipline by our customers, budget exhaustion and the COVID-19 pandemic. Activity rebounded modestly in 2021 and continued to increase throughout 2022 as we saw an increase in the volume of sand sold. Supply constraints from labor shortages negatively affected West Texas in-basin mine operations and increased demand for Northern White frac sand for the region in 2022. Demand from oil and gas companies in Western Canada and the Marcellus Shale was also strong in 2022. The increase in activity in 2022 resulted in an increase in demand and pricing for our sand, which continued throughout the first quarter of 2023. Demand for our natural sand proppant was adversely impacted in the second quarter of 2023 by the wildfires in Canada, which hindered our ability to transport sand. Notwithstanding the foregoing, our sand business remained resilient during the second quarter of 2023. As discussed above, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion
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activities and adversely impacted demand for our sand proppant services in the second half of 2023. We are beginning to see an uptick in orders for our sand in the first quarter of 2024 and anticipate higher demand in 2024, partially driven by western Canada, which we expect to be accretive to current pricing.

    As a result of adverse market conditions, production at our Muskie sand facility in Pierce County, Wisconsin has been temporarily idled since September 2018. Our contracted capacity has provided a baseline of business, which has kept our Taylor and Piranha plants operating and our costs competitive.

Energy Infrastructure Industry    

    Our infrastructure services business provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. We offer a broad range of services on electric transmission and distribution, or T&D, networks and substation facilities, which include engineering, design, construction, upgrade, maintenance and repair of high voltage transmission lines, substations and lower voltage overhead and underground distribution systems. Our commercial services include the installation, maintenance and repair of commercial wiring. We also provide storm repair and restoration services in response to storms and other disasters. We provide infrastructure services primarily in the northeastern, southwestern, midwestern and western portions of the United States.

    We currently have agreements in place with private utilities, public IOUs and Co-Ops. Since we commenced operations in this line of business, a substantial portion of our infrastructure revenue has been generated from storm restoration work, primarily from PREPA, due to damage caused by Hurricane Maria. On October 19, 2017, Cobra and PREPA entered into an emergency master services agreement for repairs to PREPA’s electrical grid. 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 master services agreement, which provided for payments of up to $900 million, to provide additional repair services and begin the initial phase of reconstruction of the electrical power system in Puerto Rico (the “second contract”). Our work under each of the contracts with PREPA ended on March 31, 2019. 

    As of December 31, 2023, PREPA owed us approximately $204.8 million for services we performed, excluding $197.5 million of interest charged on delinquent balances as of December 31, 2023. See Note 2. Summary of Significant Accounting Policies—Accounts Receivable to our consolidated financial statements included elsewhere in this report. PREPA is currently subject to bankruptcy proceedings, which were filed in July 2017 and are currently 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 Federal Emergency Management Agency, or FEMA, or other sources. Since September 30, 2019, we have been pursuing litigation in the U.S. District Court for the District of Puerto Rico and other dispute resolution efforts seeking recovery of the amounts owed to Cobra by PREPA for restoration services in Puerto Rico, which proceedings are discussed in more detail in Note 20—“Commitments and Contingencies—Litigation” included elsewhere in this report. In connection with these efforts, in 2023, an aggregate of $99 million was approved by FEMA for reimbursement to Cobra for services performed by Cobra, of which amount approximately $22.2 million was paid by PREPA to Cobra in 2023. On December 1, 2023, Cobra, as seller, and Mammoth, as guarantor, entered into an assignment agreement (the “Assignment Agreement”) with SPCP Group, LLC (“SPCP Group”), pursuant to which Cobra transferred to SPCP Group all of its rights, title and interest in $54.4 million of outstanding accounts receivable with PREPA and received net proceeds of $46.1 million. See “—Liquidity and Capital Resources—Cobra Assignment Agreement” for additional information. On December 4, 2023, following submission of a joint status report by Cobra and FEMA on December 1, 2023, in which, among other things, PREPA reported that they submitted a request for reimbursement to COR3 on November 1, 2023 for $82.4 million and is disputing approximately $1.5 million of invoices from Cobra, the Court ordered PREPA to provide a detailed summary of each of their objections to the disputed amounts and directed the parties to report the status of any remaining unpaid approved invoices in connection with the status report due on January 16, 2024. On January 16, 2024, the parties filed a joint status report in which, among other things, PREPA reported that on December 28, 2023, it received a disbursement from COR3 for the amount requested on November 1, 2023 and was in the process of paying approximately $13.4 million in approved but unpaid invoices for reimbursements for services performed by Cobra to SPCP Group as Cobra’s assignee, which amount was paid by PREPA on January 18, 2024. PREPA, however, also informed the Court that it will withhold the release of any further funds to Cobra approved by FEMA for reimbursement to Cobra due to the municipal and construction excise tax claims against Cobra allegedly aggregating to $70.4 million. Cobra believes it is exempt from the construction excise taxes and strongly disagrees with PREPA’s decision to withhold funds. On January 17, 2024, Cobra filed a Writ of Certiorari requesting the Court of Appeals to reverse the order from the Humacao Superior Court. On February 15, 2024, Cobra’s request was granted by the Court of Appeals and the order instructing PREPA to withhold the $9.0 million payment from Cobra was revoked. The case was remanded to the lower Court for continuation of the proceedings in accordance with the Court of Appeals’ order. The municipality has 15 days to request reconsideration. On January 19, 2024, the Court extended the previously ordered stay in the proceedings through April 5, 2024, and directed the parties to file a joint status report addressing (i) the status of any
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administrative appeals in connection with the November 2022 and December 2022 determination memoranda regarding the second contract, (ii) the status of any remaining approved, but unpaid invoices, and (iii) whether the parties are actively engaged in mediation to resolve their outstanding issues by March 27, 2024. Subsequent to December 31, 2023, PREPA paid $64.0 million with respect to the outstanding PREPA receivable, of which $9.6 million was paid to Cobra and $54.4 million was paid to SPCP Group, as Cobra’s assignee under the Assignment Agreement, which fully extinguished Cobra’s and Mammoth’s obligations to SPCP Group under the Assignment Agreement, and the Assignment Agreement was terminated.

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 20. 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 contracts with PREPA have concluded and we have not obtained, and there can be no assurance that we will be able to obtain, one or more contracts with other customers to replace the level of services that we provided to PREPA.

During 2022, operational improvements combined with increased crew count drove enhanced results in our infrastructure services division compared to 2021. Although our average crew count declined slightly from approximately 91 crews throughout 2022 to approximately 83 crews throughout 2023, operational efficiencies drove comparable results. Funding for projects in the infrastructure space remains strong with added opportunities expected from the Infrastructure Investment and Jobs Act, which was signed into law on November 15, 2021. We anticipate the federal spending to begin fueling additional projects in this sector and expect bidding activity to ramp up in 2024. We continue to focus on operational execution and pursue opportunities within this sector as we strategically structure our service offerings for growth, intending to increase our infrastructure services activity and expand both our geographic footprint and depth of projects, especially in fiber maintenance and installation projects.

We work for multiple utilities primarily across the northeastern, southwestern, midwestern and western portions of the United States. We believe that we are well-positioned to compete for new projects due to the experience of our infrastructure management team, combined with our vertically integrated service offerings. We are seeking to leverage this experience and our service offerings to grow our customer base and increase our revenues in the continental United States over the coming years.


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Results of Operations

The following discussion focuses on a comparison of the results of operations between the years ended December 31, 2023 and 2022. For a discussion of the results of operations for the year ended December 31, 2022 as compared to the year ended December 31, 2021, please refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2022 (filed with the SEC on February 24, 2023), which is incorporated in this report by reference from such prior report on Form 10-K.

Years Ended
December 31, 2023December 31, 2022
Revenue:(in thousands)
Well completion services$131,288 $170,663 
Infrastructure services110,537 111,452 
Natural sand proppant services39,131 51,391 
Drilling services7,126 8,380 
Other services24,054 25,174 
Eliminations(2,644)(4,974)
Total revenue309,492 362,086 
Cost of revenue:
Well completion services (exclusive of depreciation and amortization of $16,786 and $22,080, respectively, for 2023 and 2022)108,651 128,742 
Infrastructure services (exclusive of depreciation and amortization of $8,382 and $16,149, respectively, for 2023 and 2022)90,627 91,649 
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $7,734 and $8,725, respectively, for 2023 and 2022)26,324 36,783 
Drilling services (exclusive of depreciation and amortization of $4,514 and $5,810, respectively, for 2023 and 2022)7,121 7,599 
Other services (exclusive of depreciation and amortization of $7,674 and $11,506, respectively, for 2023 and 2022)17,761 18,788 
Eliminations(2,644)(4,974)
Total cost of revenue247,840 278,587 
Selling, general and administrative expenses37,458 39,554 
Depreciation, depletion, amortization and accretion45,110 64,271 
Gains on disposal of assets, net(6,041)(3,908)
Impairment of goodwill1,810 — 
Operating loss(16,685)(16,418)
Interest expense and financing charges, net(16,196)(11,506)
Other income, net42,015 40,912 
Income before income taxes9,134 12,988 
Provision for income taxes12,297 13,607 
Net loss$(3,163)$(619)

    Revenue. Revenue for 2023 decreased $52.6 million, or 15%, to $309.5 million from $362.1 million for 2022. The decline in total revenue is primarily attributable to a decrease in utilization in our well completion services division as well as a decline in tons sold in our natural sand proppant services division. Revenue derived from related parties was $1.0 million for 2023 compared to $1.1 million for 2022. Revenue by division was as follows:

Well Completion Services. Well completion services division revenue decreased $39.4 million, or 23%, to $131.3 million for 2023 from $170.7 million for 2022. Intersegment revenue, consisting primarily of revenue derived from our other services and natural sand proppant segment, totaled $0.5 million and $0.8 million, for 2023 and 2022, respectively.
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The decline in our well completion services revenue was primarily driven by decreased utilization. The number of stages completed declined 31% to 4,220 for 2023 from 6,149 for 2022. An average of 1.8 of our six fleets were active throughout 2023 compared to 3.0 fleets for 2022.

Infrastructure Services. Infrastructure services division revenue decreased $1.0 million, or 1%, to $110.5 million for 2023 from $111.5 million for 2022 primarily due to a decline in average crew count from 91 crews during the year ended December 31, 2022 to an average of 83 crews during the year ended December 31, 2023. This was partially offset by an increase in storm restoration activity of $4.5 million during the year ended December 31, 2023 compared to the year ended December 31, 2022.

Natural Sand Proppant Services. Natural sand proppant services division revenue decreased $12.3 million, or 24%, to $39.1 million for 2023, from $51.4 million for 2022. Intersegment revenue, consisting primarily of revenue derived from our well completion segment, was a nominal amount for 2023 and $2.5 million, or 5% of total sand revenue, for 2022.

The decrease in our natural sand proppant services revenue was primarily attributable to declines in freight and shortfall revenue of $7.7 million and $1.1 million, respectively, coupled with a 14% decline in tons of sand sold from approximately 1.4 million tons in 2022 to 1.2 million tons in 2023. This was partially offset by a 10% increase in average price per ton of sand sold from $27.11 in 2022 to $29.86 in 2023.

Drilling Services. Drilling services division revenue decreased $1.3 million, or 15%, to $7.1 million for 2023, from $8.4 million for 2022. Revenue derived from related parties, consisting primarily of directional drilling revenue from El Toro Resources LLC, was $0.5 million for 2023 and $0.8 million for 2022. The decrease in our drilling services revenue was primarily attributable to decreased utilization for our directional drilling business from 44% for 2022 to 36% for 2023, which was partially offset by an increase in the average dayrate.

Other Services. Revenue from other services, including our aviation, equipment rental, remote accommodation and equipment manufacturing businesses decreased $1.1 million, or 4%, to $24.1 million for 2023 from $25.2 million for 2022. Revenue derived from related parties, consisting primarily of aviation revenue from Brim Equipment Leasing, Inc., or Brim, was $0.4 million for 2023 and $0.3 million for 2022. Intersegment revenue, consisting primarily of revenue derived from our infrastructure and well completion segments, totaled $2.1 million and $1.7 million, for 2023 and 2022, respectively.

The decrease in our other services revenue was primarily due to a decline in utilization for our equipment rental business. We rented an average of 241 pieces of equipment to customers during 2023, a decrease of 3% from an average of 249 pieces of equipment rented to customers during 2022. This was offset by an increase in utilization for remote accommodations business. On average, 178 rooms were utilized per night during 2023, a 3% increase from an average of 172 rooms utilized per night in 2022.

    Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, decreased $30.8 million from $278.6 million, or 77% of total revenue, for 2022 to $247.8 million, or 80% of total revenue, for 2023. Cost of revenue by operating division was as follows:

Well Completion Services. Well completion services division cost of revenue, exclusive of depreciation and amortization expense, decreased $20.0 million, or 16%, from $128.7 million for 2022 to $108.7 million for 2023 primarily due to a decline in utilization. As a percentage of revenue, our well completion services division cost of revenue, exclusive of depreciation and amortization expense of $16.8 million in 2023 and $22.1 million in 2022, was 83% and 75%, for 2023 and 2022, respectively. The increase as a percentage of revenue is primarily due to a decrease in utilization of our pressure pumping services, resulting in a higher ratio of fixed costs to variable costs.

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, decreased $1.0 million from $91.6 million for 2022 to $90.6 million for 2023. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $8.4 million in 2023 and $16.2 million in 2022, was 82% for each of 2023 and 2022, respectively.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, decreased $10.5 million, or 29%, from $36.8 million for 2022 to $26.3
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million for 2023. As a percentage of revenue, cost of revenue, exclusive of depreciation, depletion and accretion expense of $7.7 million in 2023 and $8.7 million in 2022, was 67% and 72%, for 2023 and 2022, respectively. The decrease in cost as a percentage of revenue is primarily due to a 10% increase in average sales price.

Drilling Services. Drilling services division cost of revenue, exclusive of depreciation and amortization expense, decreased $0.5 million, or 7%, from $7.6 million for 2022 to $7.1 million for 2023. As a percentage of revenue, our drilling services division cost of revenue, exclusive of depreciation and amortization expense of $4.5 million in 2023 and $5.8 million in 2022, was 100% and 90%, for 2023 and 2022, respectively. The increase as a percentage of revenue in 2023 is primarily due to a decrease in utilization, resulting in a higher ratio of fixed costs to variable costs.

Other Services. Other services cost of revenue, exclusive of depreciation and amortization expense, decreased $1.0 million, or 5%, from $18.8 million for 2022 to $17.8 million for 2023. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $7.7 million in 2023 and $11.5 million in 2022, was 74% and 75%, for 2023 and 2022, respectively.

    Selling, General and Administrative Expenses. Selling, general and administrative expenses, or SG&A, represent the costs associated with managing and supporting our operations. SG&A expense decreased $2.1 million, or 5%, to $37.5 million for the year ended December 31, 2023 from $39.6 million for the year ended December 31, 2022 primarily due to a decrease in the provision for expected credit losses. The following is a breakout of SG&A expenses for the periods indicated (in thousands):
Years Ended
December 31, 2023December 31, 2022
Cash expenses:
Compensation and benefits$15,563 $13,729 
Professional services13,448 13,501 
Other(a)
7,693 8,012 
Total cash SG&A expense36,704 35,242 
Non-cash expenses:
Change in provision for expected credit losses(591)3,389 
Stock based compensation1,345 923 
Total non-cash SG&A expense754 4,312 
Total SG&A expense$37,458 $39,554 
a.    Includes travel-related costs, IT expenses, rent, utilities and other general and administrative-related costs.


    Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion decreased $19.2 million, or 30%, to $45.1 million for 2023 from $64.3 million in 2022. The decrease is primarily due to a decline in property and equipment depreciation expense as a result of lower capital expenditures and existing assets being fully depreciated or impaired.

Gains on Disposal of Assets, Net. Gains on the disposal of assets increased $2.1 million, or 54%, to $6.0 million for 2023 from $3.9 million in 2022. Gains on the disposal of assets is primarily related to the sale of a drilling rig, trucks, and field equipment for the years ended December 31, 2023 and trucks, land and buildings for the year ended December 31, 2022.

    Impairment of Goodwill. As a result of the sale of ARS, we performed an impairment assessment of our goodwill for the Aviation reporting unit. We determined that the carrying value of goodwill for our Aviation reporting unit exceeded the fair value, resulting in impairment expense of $1.8 million for the year ended December 31, 2023. We did not recognize any impairment of goodwill in 2022.

    Operating Loss. We reported an operating loss of $16.7 million for 2023 compared to $16.4 million for 2022. The increased operating loss in 2023 was primarily due to reduced utilization across our well completions and natural sand proppant divisions, partially offset by a decline in depreciation, depletion, amortization and accretion expense.

    Interest Expense and financing charges, net. Interest expense and financing charges, net increased $4.7 million to $16.2 million for 2023 from $11.5 million for 2022, primarily due to a $2.8 million financing charge incurred in relation to the
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Assignment Agreement with SPCP Group. See “—Liquidity and Capital Resources—Cobra Assignment Agreement” for additional information.

    Other Income, net. Other income, net increased $1.1 million during 2023 compared to 2022. We recognized interest on trade accounts receivable of $45.4 million in 2023 compared to $41.3 million in 2022. Additionally, on July 13, 2023, we sold all of our equity interests in ARS resulting in a $2.1 million gain on the sale.

    Income Taxes. During 2023, we recorded income tax expense of $12.3 million on pre-tax income of $9.1 million compared to income tax expense of $13.6 million on pre-tax income of $13.0 million for 2022. Our effective tax rate was 134.6% for 2023 compared to 104.8% for 2022. Our tax rate is affected by recurring items, such as tax rates in foreign jurisdictions and the relative amounts of income we earn in those jurisdictions, as well as discrete items, such as changes in the valuation allowance and interest and penalties that may not be consistent from year to year. See Note 14 to our consolidated financial statements for additional detail regarding our change in tax expense.

Non-GAAP Financial Measures

Adjusted EBITDA

    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 and financing charges, 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 following tables also provide a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income or (loss) for each of our operating segments for the specified periods (in thousands).

Consolidated
Years Ended December 31,
Reconciliation of net loss to Adjusted EBITDA:202320222021
Net loss$(3,163)$(619)$(101,430)
Depreciation, depletion, amortization and accretion45,110 64,271 78,475 
Gains on disposal of assets, net(6,041)(3,908)(5,147)
Impairment of goodwill1,810 — 891 
Impairment of other long-lived assets— — 1,212 
Public offering costs— — 91 
Stock based compensation1,345 923 1,191 
Interest expense and financing charges, net16,196 11,506 6,406 
Other income, net(42,015)(40,912)(5,154)
Provision (benefit) for income taxes12,297 13,607 (22,863)
Interest on trade accounts receivable45,440 41,276 34,709 
Adjusted EBITDA$70,979 $86,144 $(11,619)

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Well Completion Services
Years Ended December 31,
Reconciliation of net (loss) income to Adjusted EBITDA:202320222021
Net (loss) income$(3,782)$10,194 $(58,051)
Depreciation, depletion, amortization and accretion16,794 22,103 26,377 
Gains on disposal of assets, net(2,091)(615)(770)
Public offering costs— — 31 
Stock based compensation508 380 333 
Interest expense and financing charges, net4,502 1,940 1,107 
Other expense (income), net(343)1,843 
Interest on trade accounts receivable— — (1,841)
Adjusted EBITDA$15,933 $33,659 $(30,971)

Infrastructure Services
Years Ended December 31,
Reconciliation of net income (loss) to Adjusted EBITDA:202320222021
Net income (loss)$8,237 $4,933 $(36,711)
Depreciation, depletion, amortization and accretion8,390 16,171 21,880 
Gains on disposal of assets, net(510)(795)(286)
Impairment of goodwill— — 891 
Impairment of other long-lived assets— — 665 
Public offering costs— — 39 
Stock based compensation538 349 500 
Interest expense and financing charges, net9,753 7,390 3,925 
Other income, net(39,252)(40,470)(6,499)
Provision for income taxes11,214 13,427 712 
Interest on trade accounts receivable45,440 41,276 36,551 
Adjusted EBITDA$43,810 $42,281 $21,667 

Natural Sand Proppant Services
Years Ended December 31,
Reconciliation of net income (loss) to Adjusted EBITDA:202320222021
Net income (loss)$906 $(1,945)$(6,328)
Depreciation, depletion, amortization and accretion7,737 8,732 9,005 
Gains on disposal of assets, net(13)(89)(30)
Public offering costs— — 12 
Stock based compensation187 119 202 
Interest expense and financing charges, net540 753 474 
Other income, net(18)(14)(844)
Interest on trade accounts receivable— — (1)
Adjusted EBITDA$