Mammoth Energy Services, Inc. TUSK US Equity☆

tusk-20211231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2021

Commission File No. 001-37917

Mammoth Energy Services, Inc.

(Exact name of registrant as specified in its charter)

Securities registered pursuant to Section 12(b) of The Act:

Title of each class Trading Symbol(s) Name of each exchange on which registered

Common Stock TUSK The 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 filer ☐ Accelerated filer ☒

Non-accelerated filer ☐ Smaller 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. ☒

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, 2021 was approximately $106.6 million, calculated based on the closing price of the common stock on the Nasdaq Global Select Market on that date.

As of March 2, 2022, there were 46,684,065 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 2022 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

Glossary of Oil and Natural Gas and Electrical Infrastructure Terms i

Cautionary Note Regarding Forward-Looking Statements iv

PART I. 1

Item 1. Business 1

Item 1A. Risk Factors 21

Item 1B. Unresolved Staff Comments 43

Item 2. Properties 43

Item 3. Legal Proceedings 50

Item 4. Mine Safety Disclosure 51

PART II. 52

Item 6. [Reserved] 53

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 80

Item 8. Financial Statements and Supplementary Data 81

Item 9A. Controls and Procedures 81

Item 9B. Other Information 84

Item 9C. Disclosure Regarding Foreign Jurisdictions the Prevent Inspections 84

PART III. 85

Item 10. Directors, Executive Officers and Corporate Governance 85

Item 11. Executive Compensation 85

Item 14. Principal Accountant Fees and Services 85

PART IV. 86

Item 15. Exhibits and Financial Statement Schedules 86

SIGNATURES 89

GLOSSARY OF OIL AND NATURAL GAS AND ELECTRICAL INFRASTRUCTURE TERMS

Cementing To prepare and pump cement into place in a wellbore.

Down-hole Pertaining to or in the wellbore (as opposed to being on the surface).

Drilling rig The machine used to drill a wellbore.

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Pressure pumping Services that include the pumping of liquids under pressure.

Resource play Accumulation of hydrocarbons known to exist over a large area.

Wellbore The physical conduit from surface into the hydrocarbon reservoir.

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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 reduced or flat 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;

•the severity and duration of the COVID-19 pandemic, the related global and national health concerns and economic repercussions and the resulting negative impact on demand for Mammoth’s services;

•operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, remote work arrangements and protecting the health, safety and well-being of Mammoth’s employees;

•employee retention and increasingly competitive labor market;

•the performance of contracts and supply chain disruptions during the COVID-19 pandemic;

•general economic, business or industry conditions;

•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 effects of the recent U.S. presidential and congressional elections on energy and environmental policies;

•our ability to obtain capital or financing needed for our operations on favorable terms or at all;

•our ability to continue to comply with or, if applicable, obtain a waiver of forecasted or actual non-compliance with certain financial covenants from our lenders and comply with other terms and conditions under our recently amended revolving credit facility;

•our ability to execute our business and financial strategies;

•our ability to continue to grow our infrastructure services segment, recommence certain of our suspended oilfield services or return our natural sand proppant services segment to profitability;

•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 outcome of a government investigation relating to the contracts awarded to one of our subsidiaries by the Puerto Rico Electric Power Authority and any resulting litigation;

•the outcome or settlement of our litigation matters discussed in this report, including the adverse impact of the recent settlements with Gulfport Energy Corporation, or “Gulfport”, and MasTec Renewables Puerto Rico, LLC, on our financial condition and results of operations;

•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;

•the availability of transportation, pipeline and storage facilities and any increase in related costs;

•extreme weather conditions, such as the severe winter storms in February 2021 in the Permian Basin where we provide well completion and drilling services;

•access to and restrictions on use of water;

•technology;

•civil unrest or terrorist attacks;

•cybersecurity issues as digital technologies may become more vulnerable and experience a higher rate of cyberattacks due to increased use of remote connectivity in the workplace;

•competition within the energy services industry;

•availability of equipment, materials or skilled personnel or other labor resources;

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•payment of any future dividends;

•future operating results; and

•capital expenditures and other plans, objectives, expectations and intentions.

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 the construction and repair of the electric grid for private utilities, public investor-owned utilities and co-operative utilities through its infrastructure services businesses. We also provide products and services to enable the exploration and development of North American onshore unconventional oil and natural gas reserves. 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 infrastructure services, well completion services, natural sand proppant services, drilling services and other services. Our infrastructure services division provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our well completion services division provides hydraulic fracturing, sand hauling and water transfer services. 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 maintaining and improving electrical infrastructure as well as in increasing the ultimate recovery and present value of production streams from unconventional resources. Our complementary suite of services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

Our transformation towards an industrial based company 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. The equipment manufacturing operations have initially served the internal needs for our water transfer, equipment rental and infrastructure businesses, but we expect to expand into third party sales 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 business lines as we shift to a broader industrial focus.

Our facilities and service centers are strategically located in Ohio, Texas, Oklahoma, Wisconsin, West Virginia, Kentucky, California, Colorado 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 infrastructure and oilfield service businesses with an average of over 24 years of infrastructure services experience and over 29 years of oilfield services experience. They bring valuable expertise and long-term customer relationships to our business. We provide our infrastructure services to private utilities, public investor owned utilities, or IOUs, and cooperatives, or Co-Ops, and 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. For the years ended December 31, 2021 and 2020, our top five customers represented 35% and 50%, respectively, of our revenue.

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Recent Developments

Impact of the Ongoing COVID-19 Pandemic and Volatility in Commodity Prices

In March and April 2020, concurrent with the spread of COVID-19 and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. Beginning in March 2020, in response to the COVID-19 pandemic and the depressed commodity prices, many exploration and production companies, including our customers, substantially reduced their capital expenditure budgets. As a result, demand for our oilfield services declined at the end of the first quarter of 2020 and continued to decline further throughout the remainder of 2020. Exploration and production companies set their 2021 budgets based on the prevailing prices for oil and gas at the time. Although demand for oil and natural gas and commodity prices increased during the fourth quarter of 2021, these budgets for the publicly traded exploration and production companies remained relatively unchanged throughout 2021 with any excess cash flows used for debt repayment or shareholder returns rather than to increase production, as has been the case in the past. Although activity levels for exploration and production companies increased during the fourth quarter of 2021 and early 2022 due to the improvement in the U.S. and global economic activity, easing of the COVID-19 pandemic related restrictions, availability of vaccines and treatments and rising energy use and commodity prices, the emergence of the Delta COVID-19 variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant continued to drive economic and pricing volatility and a cautious production outlook for 2022.

On July 18, 2021, the OPEC+ reached an agreement to phase out 5.8 million Bbl per day of oil production cuts by September 2022 as prices of crude oil reached their highest levels in more than two years. Coordinated increases in oil supply by OPEC+ began in August 2021, increasing overall oil production by 400,000 Bbl per day on a monthly basis from that point forward. Further, on January 4, 2022, OPEC+ agreed to continue to raise its output target by 400,000 Bbl per day in February 2022, which is expected to further boost oil supply in response to rising demand. In its report issued on February 10, 2022, OPEC noted its expectation that world oil demand will rise by 4.15 million Bbl per day in 2022, as the global economy continues to post a strong recovery from the COVID-19 pandemic. Although this demand outlook is expected to underpin oil prices, which have already seen a seven-year high in early 2022, we cannot predict the impact of these events on commodity prices and expect a competitive market for oilfield services for the foreseeable future.

We have taken, and continue to take, responsible steps to protect the health and safety of our employees during the COVID-19 pandemic. We are continue to monitor the adverse industry and market conditions resulting from the COVID-19 pandemic and have taken mitigating steps in an effort to preserve liquidity, reduce costs and lower capital expenditures. For additional information, see "Management’s Discussion and Analysis of Financial Condition and Results of Operations".

Our Services

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

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.

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As of December 31, 2021, PREPA owed us approximately $227.0 million for services we performed, excluding $110.8 million of interest charged on these delinquent balances as of December 31, 2021. See Note 2. Summary of Significant Accounting Policies—Accounts Receivable and Note 19. Commitments and Contingencies to our consolidated financial statements and Item 1A. “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.

Our crew count declined from approximately 100 crews as of December 31, 2020 to approximately 82 crews as of December 31, 2021. Although the COVID-19 pandemic and resulting economic conditions have not had a material impact on demand or pricing for our infrastructure services, revenues for our infrastructure services have declined in 2021 as a result of certain management changes throughout the year, which resulted in crew departures, and a decline in storm restoration activities. During the third quarter of 2021, we made leadership changes in our infrastructure group. We are focused on cutting costs and enhancing accountability across the division, and we saw improvement in both areas throughout the fourth quarter of 2021.

Funding for projects in the infrastructure space remains strong with added opportunities expected in the second half of 2022 and into 2023 as a result of the Infrastructure Investment and Jobs Act, which was signed into law on November 15, 2021. We continue to 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. In late 2021, we were awarded a fiber installation contract which is expected to generate an aggregate of approximately $4.5 million in revenue over the next year. Additionally, we were awarded a multi-year electric vehicle charging station engineering contract, which could generate up to $5.0 million in revenue and will run into 2024. Both of these projects are currently in process.

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.

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 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

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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, 2021, our pressure pumping business included six high-pressure fleets consisting of an aggregate 117 high-pressure fracturing units with pump nameplate capacity of 291,750 horsepower. Currently, two of the fleets are staffed and providing services in the northeast and midcontinent regions. Over the past two years, we have converted 20 of our units to include dynamic gas blending, or DGB, capabilities to meet recent shifts in customer demand and are currently in the process of converting an additional 10 units.

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, 2021, we owned a fleet of 40 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, 2021, we owned 122 water transfer pumps and 69 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.

Natural Sand Proppant Services

In our natural sand proppant business, we mine, process and sell sand. We also buy processed sand from suppliers on the spot market and resell that sand. 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.

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.

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Drilling Services

During certain of the periods discussed in this report, we offered contract land and directional drilling services as well as rig moving services. Due to market conditions, we temporarily shut-down our contract land drilling operations beginning in December 2019. We continue to monitor market conditions to determine if and when we will recommence these services.

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, 2021, we owned 12 land drilling rigs, ranging from 800 to 1,600 horsepower, eight 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, seven 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 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.

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, 2021, we owned five MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 89 mud motors, 16 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.

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, 2021, we owned 16 trucks specifically tailored to move rigs and seven cranes to assist us in moving 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.

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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, 2021, we owned four 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 Utica Shale, Eagle Ford Shale and mid-continent region. Additionally, we provide water transfer services in the northeast region. As of December 31, 2021, we owned 18 water transfer pumps, 30 miles of layflat hose and ten miles of poly pipe for use in our water transfer operations.

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, 2021, 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, 90 rooms were utilized per night during the year ended December 31, 2021.

Equipment Manufacturing. During 2019, we commenced equipment manufacturing operations at our facility located in Oklahoma. These operations have initially served our internal needs for our water transfer, equipment rental and infrastructure businesses, but we intend 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 monitor market conditions to determine if and when we will recommence these services.

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 that combine to form up to a total of five well-testing spreads. We provided flowback services in the Appalachian Basin, the Eagle Ford Shale, the Haynesville Shale and mid-continent markets. As of December 31, 2021, we owned five production testing packages, 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, 2021, we owned two twin cementers and associated equipment and 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, 2021, we had one coiled tubing unit capable of running 25,000 feet of two and five eighths inch coil rated at 15,000 pounds per square inch, or psi, two coiled tubing units capable of running 23,500 feet of two and three eighths inch coil rated at 15,000 psi, one coiled tubing unit capable of running 24,500 feet of two inch coil rated at 15,000 psi, two coiled tubing units capable of running over 22,000 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 in service.

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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 help operators minimize the risk of such damage during completion activities. As of December 31, 2021, we had a total of four nitrogen pumping units and seven fluid pumping units. We have provided pressure control services in the Eagle Ford Shale in South Texas and the Permian Basin in West Texas.

•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, 2021, 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, 2021, we had seven fluid pumping units. Five of these units are coiled tubing double pump units capable of output of up to eight barrels per minute, and are rated for pressures up to 15,000 psi. Two of these units are quintuplex pump units capable of output of up to 15 barrels per minute, and are rated for pressures up to 15,000 psi.

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, 2021, we had a fleet of six trucks.

Crude Oil Hauling. We provide crude transportation services in the Permian Basin and mid-continent region. As of December 31, 2021, we had a fleet of 14 crude oil hauling trucks.

Our Industries

Electric Infrastructure Industry

The electrical infrastructure industry involves the construction and maintenance of the electrical power grid, including, but not limited to, 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. The industry is highly fragmented with more than 3,300 separate electric utility companies identified in the United States in 2019, spread across the following subgroups: IOUs, private utilities and Co-Ops.

Demand for our services is driven by the repair and construction of transmission 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, which impact the electrical grid. These natural disasters include, but are not limited to, thunderstorms, ice storms, snow storms, tornadoes, hurricanes, earthquakes, wildfires and lightning strikes.

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.

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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 budget. 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 and other conditions and factors, including global and national health concerns, that are beyond our control. See “Recent Developments—Impact of the Ongoing COVID-19 Pandemic and Volatility in Commodity Prices” above.

Demand for most of our oil and natural gas products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The levels of capital expenditures of our customers are predominantly driven by the prices of oil and natural gas. In March and April 2020, concurrent with the spread of COVID-19 and quarantine orders in the U.S. and worldwide, oil prices dropped sharply to below zero for the first time in history due to factors including significantly reduced demand and a shortage of storage facilities. Beginning in March 2020, in response to the COVID-19 pandemic and the depressed commodity prices, many exploration and production companies, including our customers, substantially reduced their capital expenditure budgets. As a result, demand for our oilfield services declined at the end of the first quarter of 2020 and continued to decline further throughout the remainder of 2020. Exploration and production companies set their 2021 budgets based on the prevailing prices for oil and gas at the time. Although demand for oil and natural gas and commodity prices increased during the fourth quarter of 2021, these budgets for the publicly traded exploration and production companies remained relatively unchanged throughout 2021 with any excess cash flows used for debt repayment or shareholder returns rather than to increase production, as has been the case in the past. Activity levels for exploration and production companies, however, increased during the fourth quarter of 2021 and early 2022 due to the recent improvement in the U.S. and global economic activity, easing of the COVID-19 pandemic related restrictions, availability of vaccines and treatments and rising energy use and commodity prices, the emergence of the Delta COVID-19 variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant continued to contribute to the economic and pricing volatility and a cautious production outlook for 2022.

On July 18, 2021, the OPEC+ reached an agreement to phase out 5.8 million barrels per day of oil production cuts by September 2022 as prices of crude oil reached their highest levels in more than two years. Coordinated increases in oil supply by OPEC+ began in August 2021, increasing overall oil production by 400,000 barrels per day on a monthly basis from that point forward. Further, on January 4, 2022, OPEC+ agreed to continue to raise its output target by 400,000 Bbl per day in February 2022, which is expected to further boost oil supply in response to rising demand. In its report issued on February 10, 2022, OPEC noted its expectation that world oil demand will rise by 4.15 million Bbl per day in 2022, as the global economy continues to post a strong recovery from the COVID-19 pandemic. Although this demand outlook is expected to underpin oil prices, which have already seen a seven-year high in early 2022, we cannot predict the impact of these events on commodity prices and expect a competitive market for oilfield services for the foreseeable future.

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

In 2018 and 2019, several new and existing suppliers completed planned capacity additions of frac sand supply, particularly in the Permian Basin. The industry expansion, coupled with increased capital discipline, budget exhaustion and the impact on oil demand from the COVID-19 pandemic, caused the frac sand market to become oversupplied, particularly in finer grades. With the frac sand market oversupplied, pricing for all grades has fallen significantly from the peaks experienced throughout 2018 and during the first half of 2019. This oversupply resulted in several industry participants idling and closing high cost mines in an attempt to restore the supply and demand balance. Despite such attempts, demand for our sand declined significantly in the second half of 2019 and throughout 2020 as a result of the factors discussed above. As well drilling and completions began ramping back up in 2021, overall demand for frac sand increased from the 2020 levels, reaching approximately 93 million tons in 2021, although the Northern White silica sand that we produce continued to face strong competition with Texas frac sand. We have seen a recent uptick in activity in Canada, which we currently expect to continue throughout 2022. However, rail constraints persist, causing shipping delays and adversely impacting the recovery of the

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Northern White frac sand market. We cannot predict if and when demand and pricing will recover sufficiently to return our natural sand proppant services segment to profitability.

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.

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.

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 infrastructure facilities and service centers to support our infrastructure operations in the northeast, southwest, midwest and western portions of the United States. 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, 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 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 24 years of infrastructure services experience and over 29 years of oilfield services experience. In addition, our field managers have expertise in the areas in which they operate and understand the challenges that our customers face. We believe their knowledge of our industries and 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.

•Young fleet of equipment. Our infrastructure service fleet is predominantly comprised of equipment designed to construct and repair electric transmission and distribution lines and our oilfield service fleet is predominantly comprised of equipment designed to optimize recovery from unconventional wells. Three of our pressure pumping fleets with total combined horsepower of 132,500 were built in 2017. We believe that our fleet of quality equipment will allow us to provide a high level of service to our customers. In addition, over the past two years we have converted 20 of our pressure pumping units to include DGB capabilities to meet recent shifts in customer demand and expect to convert 10 more units during 2022.

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Our Business Strategy

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. In the case of our oilfield services, 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 Permian Basin in West Texas. 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 infrastructure services division provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our well completion services division provide hydraulic fracturing services for unconventional wells as well as sand hauling services and water transfer services. Our natural sand proppant services division mines, processes and sells natural sand proppant for hydraulic fracturing. 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.

•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.

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

•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, we intend to pursue selected, accretive acquisitions of businesses and assets, primarily related to our infrastructure services, completion and production services and industrial based companies, that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence. We believe this 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, or Wexford, our largest stockholder, may help us identify acquisition opportunities. We may use our common stock as consideration for accretive acquisitions.

•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 2021, oil prices fluctuated between a low of $47.62 on January 4, 2021 and a high of $84.65 on October 26, 2021, and averaged $68.17 per barrel for the year. This extreme price volatility reduced the demand for our oilfield services. We cannot predict if or when commodity prices will stabilize and at what levels,

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but we will seek to capitalize on any increase in activity in our existing markets and diversify our operations across additional unconventional resource basins as opportunities arise.

Marketing and Customers

Our customers consist primarily of private utilities, IOUs, Co-Ops, independent oil and natural gas producers and land-based drilling contractors in North America. For the years ended December 31, 2021, 2020 and 2019, we had approximately 480, 530 and 590 customers, respectively, including American Electric Power Company, Gulfport, Liberty Oilfield Services Inc., Hilcorp Energy and Arsenal Resources. Our top five customers accounted for approximately 35%, 50% and 53%, respectively, of our revenue for the years ended December 31, 2021, 2020 and 2019. During the years ended December 31, 2021 and 2020, Gulfport accounted for 7% and 16%, respectively, of our revenue. For the year ended December 31, 2019, Gulfport and PREPA accounted for 20% and 15%, respectively, of our revenue. Our services for PREPA and Gulfport have ended. 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, 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, contract and 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 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 for our infrastructure services business include MYR Group, Inc., Quanta Services, Inc., MasTec, Inc. and EMCOR Group, Inc. Our major competitors in well completion services include Halliburton Company, U.S. Well Services, LLC, NexTier Oilfield Solutions, Inc., RPC Incorporated, Liberty Oilfield Services, Inc. and FTS International, 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 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.

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;

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•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.

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 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, 2021, 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

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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.

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

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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 redefining the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rules, and significantly reducing the waters subject to federal regulation under the Clean Water Act. On August 30, 2021, a federal court struck down the replacement rule and, on December 7, 2021, the EPA and the Corps published a proposed rule that would put back into place the pre-2015 definition of "waters of the United States," updated to reflect Supreme Court decisions, while the agencies continue to consult with stakeholders on future regulatory actions. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act. To the extent the rules expand the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

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 “—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. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already 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. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives.

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 Agreement went into effect on November 4, 2016. The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. Although the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden issued an executive order on January 20, 2021 to rejoin the Paris Agreement, which went into effect on February 19, 2021. 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% by 2030 to meet this objective. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international commitments.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely affect the oil and natural gas industry by reducing demand for hydrocarbons and by making it more expensive to develop and produce hydrocarbons,

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either of which could have a material adverse effect on future demand for our services. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

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.

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

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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, 2019, 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. Additionally, on November 15, 2021, the EPA published a proposed rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries and prohibiting venting of natural gas in certain situations. These new standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

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

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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 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 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. 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. On November 20, 2018, the Ohio EPA announced that it intends to evaluate current rules that cover air pollution emissions associated with non-conventional oil and gas facilities. The Ohio EPA is considering changes to its regulations on air quality at hydraulic fracturing and natural gas drilling sites to include compressor sites and production sites.

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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.

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

As of December 31, 2021, we had 783 full time employees. 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.

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 business and operations have been and will likely continue to be adversely affected by the COVID-19 pandemic.

•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.

•Our revolving credit facility imposes, and any of our future credit facilities may impose, restrictions on us that may affect our ability to successfully operate our business.

•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.

•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.

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•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.

•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.

•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.

•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 provides, and any future credit facilities may 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.

•A cyber incident could occur and 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 two of 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.

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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. PREPA is currently subject to bankruptcy proceedings and, 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. 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, $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, 2021, PREPA owed us approximately $227.0 million for services performed excluding $110.8 million of interest charged on these delinquent balances. PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under the contracts is largely dependent upon funding from the FEMA or other sources. On September 30, 2019, we filed a motion with the U.S. District Court for the District of Puerto Rico seeking recovery of the amounts owed to us by PREPA, which motion was stayed by the court. On March 25, 2020, we filed an urgent motion to modify the stay order and allow our recovery of approximately $62 million in claims related to a tax gross-up provision contained in the first contract. This emergency motion was denied on June 3, 2020 and the court extended the stay of our motion. On December 9, 2020, the Court again extended the stay of our motion and directed PREPA to file a status report by June 7, 2021. On April 6, 2021, we filed a motion to lift the stay order. Following this filing, PREPA initiated discussion with Cobra, which resulted in PREPA and Cobra filing a joint motion to adjourn all deadlines relative to the April 6, 2021 motion until the June 16, 2021 omnibus hearing as a result of PREPA’s understanding that FEMA would be releasing a report in the near future relating to the first contract. The joint motion was granted by the court on April 14, 2021. On May 26, 2021, FEMA issued a Determination Memorandum related to the first contract between Cobra and PREPA in which, among other things, FEMA raised two contract compliance issues and, as a result, concluded that approximately $47 million in costs were not authorized costs under the contract. On June 14, 2021, the Court issued an order adjourning Cobra’s motion to lift the stay order to a hearing on August 4, 2021 and directing Cobra and PREPA to meet and confer in good faith concerning, among other things, (i) the May 26, 2021 Determination Memorandum issued by FEMA and (ii) whether and when a second determination memorandum is expected. The parties were further directed to file an additional status report, which was filed on July 20, 2021. On July 23, 2021, with our aid, PREPA filed an appeal of the entire $47 million that FEMA de-obligated in the May 26, 2021 Determination Memorandum. The appeal is currently pending. On August 4, 2021, the Court denied Cobra’s April 6, 2021 motion to lift the stay order, extended the stay of our motion seeking recovery of amounts owed to Cobra and directed the parties to file an additional joint status report, which was filed on January 22, 2022.On January 26, 2022, the Court extended the stay and directed the parties to file a further status report by July 25, 2022.

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% and 50%, respectively, of our revenue for the years ended December 31, 2021 and 2020. Gulfport accounted for approximately 7% of our revenue for the year ended December 31, 2021 and was our largest customer for the year ended December 31, 2020, accounting for approximately 16% of our revenue; however, our services with Gulfport ended in 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. See the risk factors below for additional information. In addition, we are subject to credit risk due to the

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concentration of our customer base. In particular, PREPA owed us approximately $337.8 million (including interest charged on overdue amounts) as of December 31, 2021, as discussed in more detail below. 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.

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.

Our business and operations have been and will likely continue to be adversely affected by the COVID-19 pandemic.

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

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. Subsequent to the indictment, we received (i) a preservation request letter from the SEC related to documents relevant to an ongoing investigation it is conducting and (ii) a civil investigative demand, or CID, from the United States Department of Justice, or DOJ, requesting certain documents and answers to interrogatories relevant to an ongoing investigation DOJ is conducting. Both the SEC and DOJ investigations relate to the same subjects as those at issue in the criminal matter referenced above. We are cooperating with both the SEC and DOJ investigations. Given the uncertainty inherent in the criminal proceeding and the SEC and DOJ investigations, it is not possible at this time to determine the potential outcome or other potential impacts that they will have on 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 pending investigations and legal proceedings relating to our contracts with PREPA.

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Our revolving credit facility imposes, and any of our future credit facilities may impose, restrictions on us that may affect our ability to successfully operate our business.

Our revolving credit facility limits, and any of our future credit facilities may 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.

We cannot assure you that we will be able to maintain compliance with the covenants contained in our revolving credit facility as amended by the recent amendment discussed elsewhere in this report, or, if applicable, obtain a waiver of forecasted or actual non-compliance with certain financial covenants from our lenders. If an event of default occurs under our revolving credit facility and remains uncured, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. The lenders (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees, to be due and payable, and (iii) may have the ability to require us to apply all of our available cash to repay our outstanding borrowings.

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 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.

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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 substantial 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 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

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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.

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 the sharp decline in oil prices in 2020 and continued volatility in the oil and natural gas markets have negatively impacted, and are likely to continue to negatively 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. In early March 2020, oil prices dropped sharply and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Although commodity prices have generally recovered, they are expected to continue to be volatile as a result of production levels, inventories and demand, and national and international economic performance. Other significant factors that are likely to continue to affect commodity prices in current and future periods include, but are not limited to, the effect of U.S. energy, monetary and trade policies, U.S. and global political developments, the impact and duration of the ongoing COVID-19 pandemic and conditions in the U.S. oil and gas industry, actions of OPEC+ members, the impact of the current Russian/Ukrainian military conflict 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 capex 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 capex spend 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 current Russian/Ukrainian military conflict on the global energy and capital markets and global stability;

•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;

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•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 such as the coronavirus;

•merger and divestiture activity among oil and natural gas producers; 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.