MAMMOTH ENERGY SERVICES, INC. 10-K

Item 1. Business Overview We are an integrated, growth-oriented energy services company focused on providing products and services to enable the exploration and development of North American onshore unconventional oil and natural gas reserve as well as the construction and repair of the electric grid for private utilities, public investor-owned utilities and co-operative utilities through our infrastructure services businesses. Our primary business objective is to grow our operations and create value for stockholders through organic growth opportunities and accretive acquisitions. Our suite of services includes well completion services, infrastructure services, natural sand proppant services and other services. Our well completion services division provides hydraulic fracturing and sand hauling services. Our infrastructure services division provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells natural sand proppant used for hydraulic fracturing. In addition to these service divisions, we also provide directional drilling services, aviation services, equipment rentals, remote accommodations and equipment manufacturing. We believe that the services we offer play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources as well as in maintaining and improving electrical infrastructure. Our complementary suite of services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning. We continue to focus on growing our industrial business. We offer infrastructure engineering services focused on the transmission and distribution industry and also have equipment manufacturing operations and offer fiber optic services. Our equipment manufacturing operations provide us with the ability to repair much of our existing equipment in-house, as well as the option to manufacture certain new equipment we may need in the future. Our fiber optic services include the installation of both aerial and buried fiber. We are continuing to explore other opportunities to expand our industrial business lines. Our facilities and service centers are strategically located in Ohio, Texas, Oklahoma, Wisconsin, Kentucky, California, Colorado, Oregon, Indiana and Alberta, Canada primarily to serve the following areas: • The Utica Shale in Eastern Ohio; • Southern Ohio; • The Permian Basin in West Texas; • The Appalachian Basin in the Northeast; • The SCOOP and STACK in Oklahoma; • The Arkoma Basin in Arkansas and Oklahoma; • The Anadarko Basin in Oklahoma; • The Marcellus Shale in West Virginia and Pennsylvania; • Southeastern New Mexico; • The Barnett Shale in Texas; • The Granite Wash and Mississippi Shale in Oklahoma and Texas; • The Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma; • Southern California; and • The oil sands in Alberta, Canada. Our operational division heads have an extensive track record in the oilfield service and infrastructure businesses with an average of over 32 years of oilfield services experience and over 27 years of infrastructure services experience. They bring valuable expertise and long-term customer relationships to our business. We provide our well completion, natural sand proppant and other services to a diversified range of both public and private independent oil and natural gas producers and our infrastructure services to private utilities, public investor owned utilities, or IOUs, and cooperatives, or Co-Ops. Our Services Our revenues, operating income (loss) and identifiable assets are primarily attributable to three reportable segments: well completion services, infrastructure services and natural sand proppant services. 1 Well Completion Services Pressure Pumping . We provide pressure pumping services, also known as hydraulic fracturing, to exploration and production companies. Fracturing services are performed to enhance the production of oil and natural gas from formations having low permeability such that the flow of hydrocarbons is restricted. We have significant expertise in multistage fracturing of horizontal oil and natural gas producing wells in shale and other unconventional geological formations. Currently, we provide pressure pumping services in the Utica Shale of Eastern Ohio, the Marcellus shale in the Appalachian Basin, and the mid-continent region in Oklahoma. The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, in our case primarily sand or ceramic beads, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return for the operator. We refer to the group of fracturing units, other equipment and vehicles necessary to perform a typical fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” We usually operate on a 24-hour-per-day basis and we typically staff three crews per fleet. All of our fracturing units and high-pressure pumps are manufactured to our specifications to enhance the performance and durability of our equipment and meet our customers’ needs. Each hydraulic fracturing fleet includes a mobile, on-site control center that monitors pressures, rates and volumes, as applicable. From there, our field-level managers supervise the job site by radio. Each control center is equipped with high bandwidth satellite hardware that provides continuous upload and download of job telemetry data. The data is delivered on a real-time basis to on-site job personnel, the operator and personnel at our headquarters for display in both digital and graphical form. An important element of fracturing services is determining the proper fracturing fluid, proppants and injection program to maximize results. In virtually all of our hydraulic fracturing jobs, our customers specify the composition of the fracturing fluid to be used. The fracturing fluid may contain hazardous substances, such as hydrochloric acid and certain petrochemicals. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water. The customers remove the water from the well using a controlled flow-back process, and we are generally not involved in that process or in the disposal of the fluid. We own and operate fleets of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of a high-pressure hydraulic pump, an engine, a transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted to a flat-bed trailer. As of December 31, 2024, our pressure pumping business included six high-pressure fleets consisting of an aggregate 128 high-pressure fracturing units with pump nameplate capacity of 310,000 horsepower. Two of our six pressure pumping fleets were staffed and providing services in the northeast region as of December 31, 2024. See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Industries—Oil and Natural Gas Industry” for additional information. Sand Hauling . Our sand hauling services provide last-mile trucking and logistics services for proppant used in completion activities in the Utica Shale and SCOOP/STACK. As of December 31, 2024, we owned a fleet of 39 trucks. Water Transfer. During the periods discussed in this report, we provided water transfer services primarily for completion activities in the mid-continent region. During the fourth quarter of 2024, we idled these operations. As of December 31, 2024, we owned 95 water transfer pumps and 84 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 provisions. 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 2 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. Our average crew count declined slightly from approximately 83 crews throughout 2023 to approximately 79 crews throughout 2024. With the Infrastructure Investment and Jobs Act funds being released for infrastructure projects, we remain encouraged about the potential for growth in this sector. We are currently seeing an uptick in bidding opportunities related to engineering, fiber, and transmission and distribution, all of which are areas we believe we have differentiated and specialized capabilities. We continue to focus on operational execution and pursue opportunities within this sector as we strategically structure our service offerings for growth, intending to increase our infrastructure services activity and expand both our geographic footprint and depth of projects, especially in fiber maintenance and installation projects. We work for multiple private utilities, public IOUs and Co-Ops 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. Settlement Agreement with PREPA Since we commenced operations in this line of business, a substantial portion of our infrastructure revenue has been generated from storm restoration work, primarily from the Puerto Rico Electric Power Authority, or PREPA, due to damage caused by Hurricane Maria. On October 19, 2017, Cobra Acquisitions LLC, or Cobra, and PREPA entered into an emergency master services agreement for repairs to PREPA’s electrical grid. The one-year contract, as amended, provided for payments of up to $945 million. On May 26, 2018, Cobra and PREPA entered into a second one-year, $900 million master services agreement to provide additional repair services and begin the initial phase of reconstruction of the electrical power system in Puerto Rico. Our work under each of the contracts with PREPA ended on March 31, 2019. PREPA is currently subject to bankruptcy proceedings, which were filed in July 2017 and are currently pending in the United States District Court for the District of Puerto Rico (the “Title III Court”). As a result, PREPA’s ability to meet its payment obligations under the above-referenced agreements was largely dependent upon funding from the Federal Emergency Management Agency (“FEMA”) or other sources. Since September 30, 2019, Cobra has been pursuing litigation in the Title III Court and other dispute resolution efforts seeking recovery of the amounts owed to Cobra by PREPA for restoration services in Puerto Rico, which proceedings are discussed in more detail in the Company’s prior reports filed with the SEC. PREPA was holding approximately $18.4 million in funds (the “Withheld FEMA Funds”) received from FEMA and considered payable to Cobra but had been withheld due to garnishments asserted by three Puerto Rican municipalities (the “Specified Municipalities”) for certain municipal tax claims discussed in Mammoth’s filings with the SEC (the “Specified Municipal Tax Claims”) and for which Cobra disputed any valid garnishment. On July 22, 2024, Cobra entered into a release and settlement agreement with PREPA and the Financial Oversight and Management Board for Puerto Rico (“FOMB”), in its capacity as Title III representative for PREPA, to settle all outstanding matters between Cobra and PREPA (the “Settlement Agreement”). Under the terms of the Settlement Agreement, Cobra was allowed an administrative expense claim against PREPA of $170.0 million, plus the $18.4 million in the Withheld FEMA Funds. Cobra’s allowed claim will be paid through three installments: (i) $150.0 million on the later of (A) ten business days following approval of the Settlement Agreement by the Title III Court and (B) August 31, 2024; (ii) $20.0 million within seven days following the effective date of PREPA’s plan of adjustment; and (iii) $18.4 million (subject to providing one or more indemnity letters of credit) in the Withheld FEMA Funds within either (A) ten business days after the deadline for appealing the entry of the settlement order by the Title III Court under the applicable bankruptcy rules of procedure if no such appeal is filed, or (B) if the provisions of the settlement order allowing PREPA to release the Withheld FEMA Funds to Cobra without retaining any liability to the Specified Municipalities are appealed by the Specified Municipalities, within ten business days of the filing of the notice of such appeal. The Settlement Agreement was approved by the Company’s Board of Directors on July 22, 2024, and was also approved by the PREPA Board and by the FOMB. On September 18, 2024, the Settlement Agreement was approved by the Title III Court overruling all objections thereto and an order was entered the same day (the “Settlement Order”). On October 1, 2024, Cobra received the first installment payment of $150.0 million from the Commonwealth of Puerto Rico in connection with the Settlement Agreement with PREPA. Also on October 1, 2024, certain Puerto Rico municipalities and Foreman Electric Services Inc. that had objected to approval of the Settlement Order each filed timely notices of appeal of the Settlement Order to the United States Court of Appeals for the First Circuit. None of the foregoing parties have sought a stay of the Settlement 3 Order pending such appeals. Although the ultimate outcome of these appeals cannot be predicted with certainty, Cobra believes that the appeals are without merit. On October 18, 2024, Cobra received a payment from PREPA totaling $18.4 million under the terms of the Settlement Agreement. In connection with the receipt of the $18.4 million from PREPA, Cobra instructed Fifth Third Bank, National Association (“Fifth Third Bank”) to issue a letter of credit to PREPA under the Reimbursement Agreement in the amount of $18.4 million and transferred a total of $19.3 million to a restricted cash account maintained by Fifth Third Bank as collateral for the letter of credit. As a result of the Settlement Agreement, the Company recorded a non-cash, pre-tax charge of approximately $170.7 million in the second quarter of 2024 to reduce its accounts receivable balance from PREPA of $359.1 million, representing the amount owed to Cobra by PREPA in relation to these agreements as of June 30, 2024, including the accrued but unpaid interest, prior to the Settlement Agreement, to the amount expected to be received from the Settlement Agreement. Of the $170.7 million, $89.2 million was charged to credit loss expense, which is included in “selling, general and administrative” on the consolidated statements of comprehensive (loss) income, and $81.5 million was charged to interest on delinquent accounts receivable, which is included in “other (expense) income, net” on the consolidated statements of comprehensive (loss) income. See Note 2. “Summary of Significant Accounting Policies—Accounts Receivable” and Note 20. “Commitments and Contingencies—Litigation” to our consolidated financial statements included elsewhere in this annual report for more information. Natural Sand Proppant Services In our natural sand proppant business, we mine, process and sell sand. In the past, we have also bought processed sand from suppliers on the spot market for resale. Natural sand proppant, also known as frac sand, is the most widely used type of proppant due to its broad applicability in unconventional oil and natural gas wells and its cost advantage relative to other proppants. Natural frac sand may be used as proppant in all but the highest pressure and temperature environments and is being employed in nearly all major U.S. unconventional oil and natural gas producing basins, including those in which we operate. 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. Other Services We also offer a variety of other services including directional drilling services, aviation services, equipment rental services, remote accommodation services and equipment manufacturing services. Additionally, previously we offered contract 4 land drilling services, rig moving services, coil tubing services, pressure control services, flowback services, crude oil hauling services, cementing services and acidizing services. Directional Drilling . Our directional drilling services provide for the efficient drilling and production of oil and natural gas from unconventional resource plays. Our directional drilling equipment includes mud motors used to propel drill bits and kits for measurement-while-drilling, or MWD, and electromagnetic, or EM, technology. MWD kits are down-hole tools that provide real-time measurements of the location and orientation of the bottom-hole assembly, which is necessary to adjust the drilling process and guide the wellbore to a specific target. This technology, coupled with our complementary services, allows our customers to drill wellbores to specific objectives within narrow location parameters within target horizons. The evolution of unconventional resource reserve recovery has increased the need for the precise placement of a wellbore. Wellbores often travel across long-lateral intervals within narrow formations as thin as ten feet. Our personnel are involved in all aspects of a well from the initial planning of a customer’s drilling program to the management and execution of the horizontal or directional drilling operation. As of December 31, 2024, we owned four MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 89 mud motors, nine air motors and an inventory of related parts and equipment. Currently, we perform our directional drilling services in the Utica Shale, Anadarko Basin, Arkoma Basin, Powder River Basin and Permian Basin. 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, 2024, we owned two helicopters. Equipment Rentals . Our equipment rental services provide a wide range of oilfield related equipment used in drilling, flowback and hydraulic fracturing services. Our equipment rentals consist of cranes, light plants, generators and other oilfield related equipment. We provide equipment rental in the Permian Basin, Utica Shale and Marcellus Shale. Remote Accommodations. Our remote accommodations business provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We provide a turnkey solution for our customers’ accommodation needs. These modular camps, when assembled together, form large dormitories, with kitchen/dining facilities and recreation areas. These camps are operated as “all inclusive,” where meals are prepared and provided for the guests. The primary revenue source for these camps is lodging fees. As of December 31, 2024, we had a capacity of 764 rooms, 612 of which are at Sand Tiger Lodge, our camp in northern Alberta, Canada, and 152 of which are available to be leased as rental equipment to a third party. On average, 216 rooms were utilized per night during the year ended December 31, 2024. Equipment Manufacturing. Our equipment manufacturing operations, which are located at our facility in Oklahoma, have primarily served our internal needs for our pressure pumping, water transfer, equipment rental and infrastructure businesses, but we have the ability to expand into third party sales in the future. We also offered coil tubing services, pressure control services, flowback services, crude oil hauling services, cementing services and acidizing services. Due to market conditions, we idled our flowback, cementing and acidizing operations beginning in July 2019, our contract land drilling operations beginning in December 2019, our rig moving services 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 maintain our equipment and 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. We provided flowback services in the Appalachian Basin, the Eagle Ford Shale, the Haynesville Shale and mid-continent markets. As of December 31, 2024, we owned 20 solids control packages, four hydrostatic testing packages and seven torque service packages. Cementing and Acidizing . We provided cementing and acidizing services in the Permian Basin. Cementing services involve preparing and pumping cement into place in a wellbore to support and protect well casings and help achieve zonal isolation. Acidizing services involve pumping acid into a wellbore to improve productivity or injectivity. As of December 31, 2024, we owned four acidizing pumps. 5 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, 2024, we owned 11 land drilling rigs, ranging from 800 to 1,600 horsepower, seven of which are specifically designed for drilling horizontal and directional wells. Our drilling rigs have rated maximum depth capabilities ranging from 12,500 feet to 20,000 feet. Of these drilling rigs, six are electric rigs and five are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the power from its generators (which in the case of mechanical rigs, power the rig directly) into electricity to power the rig. Depth 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. 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. Rig Moving . We provided rig moving services in the Permian Basin. As of December 31, 2024, we owned 15 trucks specifically tailored to move rigs. 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, 2024, we owned two coiled tubing units capable of running 23,500 feet of two and three eighths inch coil rated at 15,000 psi, one coiled tubing unit capable of running 24,500 feet of two inch coil rated at 15,000 psi, two coiled tubing units capable of running 22,500 feet of two inch coil rated at 10,000 psi and one coiled tubing unit capable of running 20,500 feet of two and three eighths inch coil rated at 15,000 psi. Pressure Control . Our pressure control services consisted of nitrogen and fluid pumping services. Our pressure control services equipment is designed to support activities in unconventional resource plays with the ability to operate under high pressures without having to delay or cease production during completion operations. Ceasing or suppressing production during the completion phase of an unconventional well could result in formation damage impacting the overall recovery of reserves. Our pressure control services helped operators minimize the risk of such damage during completion activities. As of December 31, 2024, we had a total of four nitrogen pumping units and five fluid pumping units. We provided pressure control services in the Eagle Ford Shale and the Permian Basin. • Nitrogen Services. Nitrogen services involve the use of nitrogen, an inert gas, in various pressure pumping operations. When provided as a stand-alone service, nitrogen is used in displacing fluids in various oilfield applications. As of December 31, 2024, 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, 2024, we had five fluid pumping units. Three of these units are coiled tubing double pump units capable of output of up to eight barrels per minute and are rated for pressures up to 15,000 psi. Two of these units are quintuplex pump units capable of output of up to 15 barrels per minute and are rated for pressures up to 15,000 psi. Full Service Transportation . During 2019, we expanded our trucking operations to include brokering and hauling of general freight throughout the United States. As of December 31, 2024, we had a fleet of six trucks. Crude Oil Hauling . We provided crude transportation services in the Permian Basin and mid-continent region. As of December 31, 2024, we had a fleet of 13 crude oil hauling trucks. 6 Our Industries Oil and Natural Gas Industry The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and related services and products budgets. The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity, storage capacity, shortages of equipment and materials and other conditions and factors that are beyond our control. Demand for most of our oil and natural gas products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The levels of capital expenditures of our customers are driven by many factors, including the prices of oil and natural gas. Throughout 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion activities for our customers, in particular, in the Utica and Marcellus Shale natural gas plays, and, as a result, reduced demand for our well completion services. Throughout 2024, we continued to experience persistent challenges in our well completion business and other oilfield services associated with lower U.S. onshore activity and sustained weakness in the natural gas basins in which we operate. We expect 2025 completions activity to be relatively steady, with the potential for upside compared to 2024 driven by incremental demand associated with natural gas. Positive trends that may contribute to increased activity will come from LNG export capacity coming online and general electricity and power demand enhancements. We will be strategically positioned to capitalize on this anticipated demand if and when it ramps up. In response to market conditions and reduced demand, we idled 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 Increased demand from oil and gas companies in 2022 resulted in higher demand and pricing for our sand compared to 2021, which continued throughout the first quarter of 2023. Demand for our natural sand proppant was adversely impacted in the second quarter of 2023 by the wildfires in Canada, which hindered our ability to transport sand. As discussed above, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion activities and adversely impacted demand for our sand proppant services in the second half of 2023. Activity remained suppressed throughout 2024. As discussed above, we expect 2025 activity to be relatively steady, with the potential for upside compared to 2024 driven by incremental demand associated with natural gas. 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. 7 Energy Infrastructure Industry The energy infrastructure industry involves the construction and maintenance of the electrical power grid, including power generation, high voltage transmission lines, substations and low voltage distribution lines, all of which connect power generation facilities to end users. The industry also provides storm repair and restoration services in response to storms and other disasters. Demand for our services is driven by the repair and construction of transmission lines, fiber lines, substations and distribution networks and is determined by the level of expenditures of utility companies. While expansion of the electrical grid is occurring, the majority of capital expenditures spent in recent years has surrounded the repair and maintenance of existing networks. Another factor that significantly influences the level of spending in the industry are natural disasters, including thunderstorms, ice storms, snow storms, tornadoes, hurricanes, earthquakes, wildfires and lightning strikes, all of which can impact the electrical grid. Certain barriers to entry exist in the markets in which we operate, including adequate financial resources, technical expertise, high safety ratings and a proven track record of operational success. We compete based upon our industry experience, technical expertise, financial and operational resources, geographic presence, industry reputation, safety record and customer service. While we believe our customers consider a number of factors when selecting a service provider, they generally award most of their work through a bid process. Consequently, price is often a principal factor in determining which service provider is selected. We believe that the age of the existing infrastructure across the United States and the spending trends in North America will benefit our operations and our ability to achieve our business objectives. Funding for projects in the infrastructure space remains strong with added opportunities since the Infrastructure Investment and Jobs Act was signed into law on November 15, 2021. Our Strengths Our primary business objective is to grow our operations and create value for our stockholders through organic growth opportunities and accretive acquisitions. We believe that the following strengths position us well to capitalize on activity in unconventional resource plays and achieve our primary business objective: • Strategic geographic positioning. We currently operate facilities and service centers to support our oilfield service operations in major unconventional resource plays in the United States, including the Utica Shale in Eastern Ohio, the Permian Basin in West Texas and Southeastern New Mexico, the SCOOP/STACK in Oklahoma, the Marcellus Shale in West Virginia, the Granite Wash in Oklahoma and Texas, the Cana Woodford Shale in Oklahoma and the oil sands in Alberta, Canada. We 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. We currently operate infrastructure facilities and service centers to support our infrastructure operations in the northeastern, southwestern, midwestern and western portions of the United States. • 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 32 years of oilfield services experience and over 27 years of infrastructure services experience. In addition, our field managers have expertise in the areas in which they operate and understand the challenges that our customers face. We believe their knowledge of our industries and business lines enhances our ability to provide innovative, client-focused and basin-specific customer service, which we also believe strengthens our relationships with our customers. • Fleet of equipment . Our oilfield service fleet is predominantly comprised of equipment designed to optimize recovery from unconventional wells and our infrastructure service fleet is predominantly comprised of equipment designed to construct and repair electric transmission and distribution lines. We believe that our fleet of quality equipment will allow us to provide a high level of service to our customers. 8 Our Business Strategy We intend to achieve our primary business objective by the successful execution of our business plan to strategically deploy our equipment and personnel to provide well completion services, natural sand proppant services and other energy services in unconventional resource plays, including the Utica Shale in Ohio, the SCOOP/STACK in Oklahoma and the Marcellus Shale in West Virginia. We intend to achieve our primary business objective in connection with our infrastructure services by the successful execution of our business plan to strategically deploy equipment and personnel to provide infrastructure services across the United States. We believe our infrastructure services optimize our customers’ ability to maintain, improve and expand their infrastructure and that our oil and natural gas services optimize our customers’ ultimate resources recovery and present value of hydrocarbon reserves. We seek to create cost efficiencies for our customers by providing a suite of complementary services designed to address a wide range of our customers’ needs. Specifically, we strive to create value for our stockholders through the following strategies: • Leverage our broad range of services for cross-selling opportunities. We offer a complementary suite of services and products. Our well completion services division provide hydraulic fracturing services for unconventional wells as well as sand hauling services and water transfer services. Our infrastructure services division provides engineering, design, construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells natural sand proppant for hydraulic fracturing. Additionally, we provide directional drilling services, equipment rentals, remote accommodations and equipment manufacturing. We intend to leverage our existing customer relationships and operational track record to cross sell our services and increase our exposure and product offerings to our existing customers, broaden our customer base and expand opportunistically to other geographic regions in which our customers have operations, as well as to create operational efficiencies for our customers. • Expand our energy infrastructure business. On November 15, 2021, President Biden signed the Infrastructure Investment and Jobs Act into law. This has brought new opportunities in the infrastructure industry, including new fiber-related projects. We consistently monitor market conditions and intend to expand the capacity and scope of our energy infrastructure services as demand warrants in geographic areas in which we currently operate, as well as in new geographic areas. • Capitalize on activity in the unconventional resource plays. Our oil and natural gas service equipment is designed to provide a broad range of services for unconventional wells, and our operations are strategically located in major unconventional resource plays. During 2024, oil prices fluctuated between a low of $65.75 on September 10, 2024, and a high of $86.91 on April 5, 2024, and averaged $75.79 per barrel for the year. During 2024, natural gas prices fluctuated between a low of $1.58 on February 15, 2024, and a high of $3.95 on December 24, 2024, and averaged $2.41 per MMBtu for the year. We saw a decline in commodity pricing during 2024, resulting in lower utilization and margins for our oilfield services divisions. • Maintain a conservative balance sheet. We seek to maintain a conservative balance sheet, which allows us to better react to changes in commodity prices and related demand for our services, as well as overall market conditions. We used a portion of the proceeds received from our Settlement Agreement with PREPA to pay, in full, all amounts owed under our term credit facility and terminated the facility. As of December 31, 2024, we had no outstanding debt and unrestricted cash of $61.0 million. • 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 and industrial based companies that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence. We believe this approach will help facilitate the strategic expansion of our customer base, geographic presence and service offerings. We also believe that our industry contacts and those of Wexford Capital LP (“Wexford”), our largest stockholder, may help us identify acquisition opportunities. We may use our common stock as consideration for accretive acquisitions. 9 Marketing and Customers Our customers consist primarily of independent oil and natural gas producers, land-based drilling contractors, private utilities, IOUs, and Co-Ops in North America. For the years ended December 31, 2024, 2023 and 2022, we had approximately 259, 360 and 410 customers, respectively, including Oncor Electric Delivery Company, LLC, San Diego Gas & Electric Company, Kentucky Utilities Company, Duke Energy and Apex Energy Services. Our top five customers accounted for approximately 34%, 35% and 36%, respectively, of our revenue for the years ended December 31, 2024, 2023 and 2022. Although we believe we have a broad customer base and wide geographic coverage of operations, it is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer decides not to continue to use our services and is not replaced by new or existing customers, our revenue would decline and our operating results and financial condition would be harmed. Operating Risks and Insurance Our operations are subject to hazards inherent in the energy services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause: • personal injury or loss of life; • damage or destruction of property, equipment, natural resources and the environment; and • suspension of operations. In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims. Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury. Despite our efforts to maintain safety standards, from time to time we have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations. We maintain commercial general liability, workers’ compensation, business auto, commercial property, motor truck cargo, umbrella liability, professional liability, cybersecurity, in certain instances, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. With respect to our hydraulic fracturing operations, coverage would be available under our policy for any surface or subsurface environmental clean-up and liability to third parties arising from any surface or subsurface contamination. We also have certain specific coverages for some of our businesses, including our remote accommodation services, pressure pumping services, directional drilling services and infrastructure engineering services. Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See Item 1A. “ Risk Factors ” for a description of certain risks associated with our insurance policies. 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 10 most recent testing date. We also regularly monitor pressure levels in the treating iron used for fracturing and the surface casing to verify that the pressure and flow rates are consistent with the job specific model in an effort to avoid failure. As part of our safety procedures, we also have the capability to shut down our pressure pumping and fracturing operations both at the pumps and in our data van. In addition, we maintain spill kits on location for containment of pollutants that may be spilled in the process of providing our hydraulic fracturing services. The spill kits are generally comprised of pads and booms for absorption and containment of spills, as well as soda ash for neutralizing acid. Fire extinguishers are also in place on job sites at each pump. Historically, we have used third-party contractors to provide remediation and spill response services when necessary to address spills that were beyond our containment capabilities. None of these prior spills were significant, and we have not experienced any material incidents, citations or legal proceeding relating to our hydraulic fracturing or crude hauling services for environmental concerns. To the extent our hydraulic fracturing or other energy services operations result in a future spill, leak or other environmental impact that is beyond our ability to contain, we intend to engage the services of such remediation company or an alternative company to assist us with clean-up and remediation. Competition The markets in which we operate are highly competitive. To be successful, a company must provide services and products that meet the specific needs of oil and natural gas exploration and production companies, drilling services contractors, private utilities, IOUs and Co-Ops at competitive prices. We provide our services and products across the United States and in Alberta, Canada and we compete against different companies in each geographic area and service and product line we offer. Our competition includes many large and small energy service companies, including the largest integrated oilfield services companies and energy infrastructure companies. Our major competitors in well completion services include Halliburton Company, Evolution Well Services, NexTier Oilfield Solutions, Inc., Liberty Oilfield Services, Inc. and ProFrac Holding Corp. Our major competitors for our infrastructure services business include MYR Group, Inc., Quanta Services, Inc., MasTec, Inc. and EMCOR Group, Inc. Our major competitors in our natural sand proppant services business are Badger Mining Corporation, Covia Holdings Corporation, Hi-Crush Partners LP, Capital Sand Proppants LLC, Athabasca Minerals Inc., Source Energy Services Ltd., and U.S. Silica Holdings Inc. We believe that the principal competitive factors in the market areas that we serve are quality of service and products, reputation for safety, technical proficiency, availability and price. While we must be competitive in our pricing, we believe our customers select our services and products based on the local leadership and expertise that our field management and operating personnel use to deliver quality services and products. Regulation We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, permitting and inspection requirements applicable to construction projects, building and electrical codes regulations, government project regulations, the handling of hazardous materials, the transportation of explosives, the protection of human health and the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance which is incorporated into our daily operating procedures. The oil and natural gas and infrastructure industries are subject to environmental and other regulation pursuant to local, state and federal legislation. Transportation Matters In connection with the transportation and relocation of our equipment and shipment of frac sand, crude oil and general cargo, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier 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 11 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, 2024, 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 its intention to revise its safety rating system to ensure greater consistency in results, continually improve the quality of data used and help motor carriers better understand their results. These changes are expected to go into effect in 2025. At this time, we cannot predict the effect these revisions may have on our safety rating. Environmental Matters and Regulation Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before commencing operations, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with our operations, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is strict (i.e., no showing of “fault” is required) and can be joint and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry and infrastructure industry in general. We have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. Waste Handling . We handle, transport, store and dispose of wastes that are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. 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 12 such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA, or the “Superfund” law, and analogous state laws, generally imposes liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability, that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed substances (including substances disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. NORM . In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials associated with oil and gas deposits and, accordingly may result in the generation of wastes and other materials containing naturally occurring radioactive materials, or NORM. NORM exhibiting levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because certain of the properties presently or previously owned, operated or occupied by us may have been used for oil and gas production operations, it is possible that we may incur costs or liabilities associated with NORM. Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers, which we refer to as the Corps. The scope of waters regulated under the CWA has fluctuated in recent years. On June 29, 2015, the EPA and the Corps jointly promulgated final rules expanding the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rules, and significantly reducing the waters subject to federal regulation under the Clean Water Act. On August 30, 2021, a federal court struck down the replacement rule and, on January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015. However on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the CWA. On September 8, 2023, the EPA and the Corps published a final rule conforming their regulations to the Supreme Court decision. These recent actions have provided some clarity. However, to the extent the EPA and the Corps broadly interpret their jurisdiction and expand the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The appointment of a new EPA administrator may mitigate enforcement. 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. 13 Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, our sand proppant services operations are subject to air permits issued by the Wisconsin Department of Natural Resources regulating our emission of fugitive dust and other constituents. These and other laws and regulations may increase the costs of compliance for some facilities where we operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas and infrastructure projects. Climate Change . In recent years, federal, state and local governments have taken steps to reduce emissions of carbon dioxide, methane and other greenhouse gases, collectively referred to as GHGs. For example, the Infrastructure Investment and Jobs Act of 2021 and the Inflation Reduction Act of 2022 (the “IRA”) include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge, which will be phased-in starting in 2024. On January 12, 2024, the EPA announced a proposed rule to implement the methane emissions charge. These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels towards lower or zero carbon emissions alternatives, which could decrease demand for our well completion, natural sand proppant and other services related to the oil and natural gas industry. The EPA has also finalized a series of GHG monitoring, reporting and emissions control rules for the oil and natural gas industry, and almost one-half of the states have taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. Also, states have imposed increasingly stringent requirement related to the venting or flaring of gas during oil and gas operations. At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its greenhouse gas emissions by 50 to 52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and other world leaders made further commitments to reduce greenhouse gas emission, including reducing global methane emissions by at least 30 percent by 2030 (from 2020 levels) to meet this objective. More than 150 countries have now signed on to this pledge. Most recently, at the 28th Conference of the Parties in the United Arab Emirates, world leaders agreed to transition away from fossil fuels in a just, orderly and equitable manner and to triple renewables and double energy efficiency globally by 2030. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international commitments. However, President Trump has recently announced he intends for the United States to withdraw from the 2015 Paris agreement. 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. 14 Endangered Species Act Environmental laws such as the Endangered Species Act, as amended, or the ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. Regulation of Hydraulic Fracturing A portion of our business is dependent on our ability to conduct hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals (also called “proppants”) under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plans. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities and the environmental impacts of discharges from CWT facilities. Furthermore, legislation to amend the Safe Drinking Water Act, or SDWA, to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards, which we refer to as NSP standards, to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended the NSP standards to impose new standards for methane and VOC emissions for certain new, modified and reconstructed equipment, processes and activities across the oil and natural gas sector. However, on August 13, 2020, in response to an executive order by former President Trump to review and revise unduly burdensome regulations, the EPA amended the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. On June 30, 2021, President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments (with the exception of some technical changes) thereby reinstating the 2012 and 2016 New Source Performance standards. The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards. Additionally, on December 2, 2023, the EPA announced a final rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries and prohibiting venting of natural gas in certain situations. President Trump has indicated his support for withdrawal of EPA’s proposed rule imposing a fee on methane emissions from oil and gas facilities. 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, 15 implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. Also, on November 18, 2016, the BLM finalized a waste prevention rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. On March 28, 2017, the Trump Administration issued an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. A coalition of environmentalists, tribal advocates and the State of California filed lawsuits challenging the rule rescission. Also, on September 28, 2018, the BLM finalized revisions to the waste prevention rule to reduce “unnecessary compliance burdens”. However, a federal court struck down the scaled-back rule on July 15, 2020, and shortly thereafter, on October 8, 2020, another federal court struck down the 2016 waste prevention rule. On November 28, 2022, the BLM announced a proposed replacement rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and Indian lands, which would require the use of upgraded equipment in some cases and would place time and volume limits on royalty-free flaring. Also, on July 24, 2023, the BLM published a proposed rule to update its oil and gas leasing regulations, which would increase bonding requirements and raise royalty rates. At this time, it is uncertain when, or if, the rules will be implemented, and what impact they would have on our operations. There are certain governmental reviews either underway or being proposed that focus on the environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. Several states and local jurisdictions in which we or our customers operate have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards, require the disclosure of the composition of hydraulic fracturing fluids and/or impose restrictions on the use of produced water from hydraulic fracturing activities or moratoriums on new produced water well permits in an effort to control induced seismicity. Any increased regulation of hydraulic fracturing or related activities could reduce the demand for our services and materially and adversely affect our reserves and results of operations. There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our customers’ fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative or regulatory changes could cause us or our customers to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing. Regulation of Natural Sand Proppant Services The MSHA has primary regulatory jurisdiction over commercial silica operations, including quarries, surface mines, underground mines and industrial mineral processing facilities. MSHA representatives perform at least two annual inspections of our production facilities to ensure employee and general site safety. To date, these inspections have not resulted in any citations for material violations of MSHA standards, and we believe we are in material compliance with MSHA requirements. 16 Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. These binding rules and regulations are subject to changes in interpretation or enforcement. Although changes to the regulatory burden on the oil and natural gas industry could affect the demand for our services, we would not expect to be affected any differently or to any greater or lesser extent than other companies in the industry with similar operations. Drilling . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The states, and some counties and municipalities, in which we operate also regulate one or more of the following: • the location of wells; • the method of drilling and casing wells; • the timing of construction or drilling activities, including seasonal wildlife closures; • the surface use and restoration of properties upon which wells are drilled; • the plugging and abandoning of wells; and • notice to, and consultation with, surface owners and other third parties. Federal, state and local regulations provide detailed requirements for the plugging and abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. State Regulation . The states in which we or our customers operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowable from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but they may do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from wells and to limit the number of wells or locations our customers can drill. 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. Regulation of Infrastructure Services In our infrastructure business, our operations are subject to various federal, state and local laws and regulations including: • licensing, permitting and inspection requirements applicable to contractors, electricians and engineers; • regulations governing environmental and conservation matters; • regulations relating to worker safety; • permitting and inspection requirements applicable to construction projects; • wage and hour regulations; • building and electrical codes; and • special bidding, procurement and other requirements on government projects. We believe that we have all the licenses required to conduct our energy infrastructure services and that we are in substantial compliance with applicable regulatory requirements. Our failure to comply with applicable regulations could result in substantial fines or revocation of our operating licenses, as well as give rise to termination or cancellation rights under our contracts or disqualify us from future bidding opportunities. 17 OSHA Matters We are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. Compliance with these laws and regulations has not had a material adverse effect on our operations or financial position. Employees, Safety and Diversity As of December 31, 2024, we had 639 full time employees. The number of employees fluctuates depending on the current and expected demand for our services. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full-time employees. We view our employees as our greatest asset and actively recruit talented people regardless of gender or ethnic background. We also promote diversity, inclusion and equal employment opportunities by evaluating and promoting employees based on skills and performance alone, while also seeking to attract and retain a diverse workforce and continuing to cultivate an inclusive and respectful work environment. One of five of our current board members is ethnically diverse. Further, as of December 31, 2024, over 9% of our employees were women and 24 of 117 employees holding managerial and other key positions within the organization are women. Also, over 13% of our employees self-identify as ethnic minorities as of December 31, 2024. Further, we invest in the learning and development of our employees. We strive to identify talent and to provide employees who demonstrate exceptional performance with opportunities and training to progress to higher levels within the organization. We maintain a culture of safety, committed to the protection of the health and safety of our employees as well as preserving the environment and our relationships with the communities in which we operate. We place a strong emphasis on the safe execution of our operations, including safety training for our employees. We have a comprehensive approach to formulating and managing training requirements for our operational employees. This includes periodic environmental, health and safety meetings, a combination of live in-person training and computer-based training tailored to specific job duties and operational activities, and comprehensive safety reference material. In addition, our safety recognition program encourages employees throughout our organization to focus on conducting operations in accordance with our strict safety standards. Further, we work closely with federal, state and local governments and community organizations to help ensure that our operations comply with legal requirements and community standards. Lastly, when our employees identify a heightened safety risk, we respond quickly to mitigate the risk through communication, coordination and, if appropriate, a change in policy, procedures and training. We believe that our customers select their operational partners based in part on the quality of their safety and compliance records, and therefore, we will continue to make investments in this area. We also empower all personnel with stop-work authority (“SWA”) as a tool for helping ensure safety. Our SWA policy empowers our employees to stop work whenever they identify unsafe work conditions. When SWA is employed, operations cease until the risk is addressed and both the employee and management agree that it is safe to resume work. See also “Safety and Remediation Program” below for additional information. Availability of Company Reports Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.mammothenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the Securities and Exchange Commission (the “SEC”) . Risk Factors Summary The following is a summary of the principal risks that could adversely affect our business, operations and financial results. Please refer to Item 1A “Risk Factors” of this Form 10-K below for additional discussion of the risks summarized in this Risk Factors Summary. 18 Risks Related to Our Business and the Industries We Serve • 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. • Cobra, one of our infrastructure services subsidiaries, was party to service contracts with PREPA. Due to PREPA’s bankruptcy proceedings, 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 the remaining amount owed to us under the Settlement Agreement, our financial condition, results of operations and cash flows may be materially and adversely affected. • Our revolving credit facility impose restrictions on us that may affect our ability to successfully operate our business. • A portion of our business depends on the oil and natural gas industry and particularly on the level of exploration and production activity within the United States and Canada, and continued volatility in the oil and natural gas markets have impacted, and are likely to continue to impact, our oilfield services and, as a result, our business, financial condition, results of operations, cash flows and stock price. • The cyclicality of the oil and natural gas industry may cause our operating results to fluctuate. • If oil prices or natural gas prices decline, the demand for our oil and natural gas services could be adversely affected. • Advancements in oilfield service technologies could have a material adverse effect on our business, financial condition, results of operations and cash flows. • 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 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 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 revolving credit facility. • An increase in the prices of certain materials used in our businesses could adversely affect our business, financial condition, results of operation and cash flows. • 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. • 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 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, which could have a material adverse effect on our financial condition and results of operations. • Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition. • 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. • The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements. • We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations. • If our intended expansion of our business is not successful, our financial condition, profitability and results of operations could be adversely affected, and we may not achieve increases in revenue and profitability that we hope to realize. 19 • 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 and regulations that may subject us to substantial liability or require us to take actions that will adversely affect our results of operations. • 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. • We are subject to cyber security risks. Cyber incidents or intrusions may result in information theft, 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. • 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 and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our common stockholders’ best interests. • If the price of our common stock fluctuates significantly, your investment could lose value. • Wexford beneficially owns a substantial amount of our common stock and may sell such common stock in the public or private markets. Sales of these shares of common stock or sales of substantial amounts of our common stock by other stockholders, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. • If securities or industry analysts do not publish research or reports about our business, if they adversely revise their recommendations regarding our stock or if our operating results do not meet their expectations, the price of our stock could decline. • We may issue preferred stock whose terms could adversely affect 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. • Our certificate of incorporation designates courts in the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers or other employees. • The declaration of dividends on our common stock is within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends in the future or at levels anticipated by our stockholders. • Our ability to repurchase stock may be limited and no assurance can be given that we will be able to effectuate our stock repurchase program in the future at indicated levels or at all. 20