What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2024-03-01 compared with 2023-02-24 · 122 added, 113 removed, 549 unchanged (30% of the section changed)

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We provide our well completion, natural sand proppant, drilling and other services to a diversified range of both public and private independent oil and natural gas producers and our infrastructure services to private utilities, public investor owned utilities, or IOUs, and cooperatives, or Co-Ops.

For the years ended December 31, 2022 and 2021, our top five customers represented 36% and 35%, respectively, of our revenue.

Recent Developments

Our Response to COVID-19 and Related Market Conditions

We have taken, and continue to take, responsible steps to protect the health and safety of our employees during the COVID-19 pandemic.

We are also continuing to monitor the industry and market conditions resulting from the COVID-19 pandemic and have taken mitigating steps in an effort to preserve liquidity, reduce costs and lower capital expenditures.

These actions have included reducing headcount, adjusting pay and limiting spending.

We will continue to take further actions that we deem to be in the best interest of the Company and our stockholders if the adverse conditions recur.

Given the dynamic nature of these events, we are unable to predict the ultimate impact of the COVID-19 pandemic, the volatility in commodity markets, inflationary pressures, rising interest rates, any changes in the near-term or long-term outlook for our industries or overall macroeconomic conditions on our business, financial condition, results of operations, cash flows and stock price or the pace or extent of any subsequent recovery.

Although demand across our three largest segments has improved during 2022 and remained strong in the fourth quarter of 2022, we continue to address the external challenges in today’s economic environment as we remain disciplined with our spending and are focused on continuing to improve our operational efficiencies and cost structure and on enhancing value for our stockholders.

Our revenues, operating income (loss) and identifiable assets are primarily attributable to four reportable segments:

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As of December 31, 2023, our pressure pumping business included six high-pressure fleets consisting of an aggregate 128 high-pressure fracturing units with pump nameplate capacity of 310,000 horsepower.

Currently, five of our six pressure pumping

fleets are staffed and providing services in the northeast and mid-continent regions.

Over the past two years, we have converted 30 of our units to include dynamic gas blending, or DGB, capabilities to meet recent shifts in customer demand.

Further, subject to market conditions, supply chain constraints and liquidity requirements, we have plans to upgrade our sixth spread to Tier 4, dual fuel and put it into operation in the second half of 2023, as well as upgrade two existing spreads to Tier 2, dual fuel.

This would give us a total of four dual fuel fleets by year-end 2023.

One of our six pressure pumping fleets was staffed and providing services in the northeast region as of December 31, 2023.

Over the past two years, we have converted two fleets to include dynamic gas blending, or DGB, capabilities to meet recent shifts in customer demand.

Further, subject to market conditions and liquidity requirements, we have plans to upgrade one additional fleet in 2024.

See also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Industries—Oil and Natural Gas Industry” for additional information.

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As a result, PREPA’s ability to meet its payment obligations under the contracts is largely dependent upon funding from the FEMA or other sources.

As of December 31, 2022, PREPA owed us approximately $227.0 million for services we performed, excluding $152.0 million of interest charged on these delinquent balances.

As of December 31, 2023, PREPA owed Cobra approximately $ 204.8 million for services performed, excluding $ 197.5 million of interest charged on delinquent balances.

Subsequent to December 31, 2023, PREPA paid an aggregate of $ 64.0 million with respect to the PREPA account receivable, of which $ 9.6 million was paid to Cobra and $ 54.4 million was paid to SPCP Group, LLC (“SPCP Group”) under the assignment agreement with Cobra, pursuant to which on December 1, 2023, Cobra transferred approximately $ 54.4 million of its outstanding PREPA receivable to SPCP Group in exchange for Cobras receipt of $ 46.1 million in net proceeds.

Following the payment of $54.4 million to SPCP Group, all of Cobra’s and Mammoth’s obligations under the assignment agreement were fully extinguished and the agreement was terminated.

Summary of Significant Accounting Policies—Accounts Receivable and Note 20.

Commitments and Contingencies to our consolidated financial statements and Item 1A.

“Risk Factors—Risks Related to Our Business and the Industries We Serve” included elsewhere in this annual report for more information regarding these delinquent balances as well as other legal actions and governmental investigations related to our work for PREPA.

Although the COVID-19 pandemic and resulting economic conditions have not had a material impact on demand or pricing for our infrastructure services, revenues for our infrastructure services declined in 2021 as a result of certain management changes throughout the year, which resulted in crew departures, and a decline in storm restoration activities.

During the third quarter of 2021, we made leadership changes in our infrastructure group and have focused on cutting costs, improving margins and enhancing accountability across the division.

During 2022, operational improvements combined with increased crew count drove enhanced results.

Our average crew count increased from approximately 82 crews as of December 31, 2021 to approximately 91 crews as of December 31, 2022, and we continue to add crew capacity for a sector that has a healthy bidding environment.

Commitments and Contingencies to our consolidated financial statements and Item 1A., and “Risk Factors—Risks Related to Our Business and the Industries We Serve” included elsewhere in this annual report for more information regarding these delinquent balances as well as other legal actions and governmental investigations related to our work for PREPA, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cobra Assignment Agreement” for additional information regarding the assignment agreement with SPCP Group.

During 2022, operational improvements combined with increased crew count drove enhanced results in our infrastructure services division compared to 2021.

Although our average crew count declined slightly from approximately 91 crews throughout 2022 to approximately 83 crews throughout 2023, operational efficiencies drove comparable results.

Funding for projects in the infrastructure space remains strong with added opportunities expected from the Infrastructure Investment and Jobs Act, which was signed into law on November 15, 2021.

We anticipate the federal spending to begin fueling this sector in 2023.

expand both our geographic footprint and depth of projects, especially in fiber maintenance and installation projects.

In late 2021, we were awarded a fiber installation contract as well as an electric vehicle charging station engineering contract.

Both of these projects are currently in process.

We anticipate the federal spending to begin fueling additional projects in this sector and expect bidding activity to ramp up in 2024.

We continue to focus on operational execution and pursue opportunities within this sector as we strategically structure our service offerings for growth, intending to increase our infrastructure services activity and expand both our geographic footprint and depth of projects, especially in fiber maintenance and installation projects.

We work for multiple utilities primarily across the northeastern, southwestern, midwestern and western portions of the United States.

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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 and resold that 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.

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We also utilize a destination transloading facility in Yorkville, Ohio, to serve the Utica Shale, and utilize destination transloading facilities located in other North American resource plays, including the Montney Shale, to meet our customers’ delivery needs.

In the fourth quarter of 2022, we entered into two sand supply agreements with third-party service providers with terms of 12 months and 21 months, respectively, beginning on January 1, 2023.

Under the terms of the agreements, we have agreed to supply, in aggregate, approximately 1.75 million tons of sand over the contract periods.

In the fourth quarter of 2023, we entered into a sand supply agreement with a third-party service provider.

Under the terms of the agreement, we have agreed to supply, in aggregate, approximately 709 thousand tons of sand over the contract period of 12 months.

Drilling Services

During certain of the periods discussed in this report, we offered contract land and directional drilling services as well as rig moving services.

Due to market conditions, we temporarily shut-down our contract land drilling operations beginning in December 2019.

Due to market conditions, we temporarily shut-down our rig moving services in April 2020 and our contract land drilling operations beginning in December 2019.

We continue to maintain our equipment and monitor market conditions to determine if and when we will recommence these services.

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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.

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.

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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, 2022, we owned four MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 89 mud motors, 16 air motors and an inventory of related parts and equipment.

As of December 31, 2023, we owned four MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 89 mud motors, nine air motors and an inventory of related parts and equipment.

Currently, we perform our directional drilling services in the Utica Shale, Anadarko Basin, Arkoma Basin, Powder River Basin and Permian Basin.

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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, 2022, we owned 12 land drilling rigs, ranging from 800 to 1,600 horsepower, eight of which are specifically designed for drilling horizontal and directional wells.

As of December 31, 2023, we owned 11 land drilling rigs, ranging from 800 to 1,600 horsepower, seven of which are specifically designed for drilling horizontal and directional wells.

Our drilling rigs have rated maximum depth capabilities ranging from 12,500 feet to 20,000 feet.

Of these drilling rigs, seven are electric rigs and five are mechanical rigs.

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.

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.

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Due to market conditions, we temporarily shut-down our rig moving operations beginning in April 2020.

As of December 31, 2022, we owned 14 trucks specifically tailored to move rigs and seven cranes.

As of December 31, 2023, we owned 15 trucks specifically tailored to move rigs.

Other Services

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Additionally, we provide helicopter training and response services.

As of December 31, 2022, we owned four helicopters.

As of December 31, 2023, we owned two helicopters.

Equipment Rentals .

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Our equipment rentals consist of cranes, light plants, generators and other oilfield related equipment.

We provide equipment rental in the Utica Shale, Eagle Ford Shale and mid-continent region.

Additionally, we provide water transfer services in the northeast region.

As of December 31, 2022, we owned 18 water transfer pumps, 30 miles of layflat hose and ten miles of poly pipe for use in our water transfer operations.

We provide equipment rental in the Permian Basin, Utica Shale and Marcellus Shale.

Remote Accommodations.

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Equipment Manufacturing.

During 2019, we commenced equipment manufacturing operations at our facility located in Oklahoma.

These operations have initially served our internal needs for our pressure pumping, water transfer, equipment rental and infrastructure businesses, but we have the ability to expand into third party sales in the future.

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

We also offered coil tubing services, pressure control services, flowback services, crude oil hauling services, cementing services and acidizing services during certain of the periods discussed in this report.

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Flowback involves the process of allowing fluids to flow from the well following a treatment, either in preparation for an impending phase of treatment or to return the well to production.

Our flowback equipment consists of manifolds, accumulators, valves, flare stacks and other associated equipment that combine to form up to a total of five well-testing spreads.

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, 2022, we owned five production testing packages, 20 solids control packages, four hydrostatic testing packages and seven torque service packages.

As of December 31, 2023, we owned 20 solids control packages, four hydrostatic testing packages and seven torque service packages.

Cementing and Acidizing .

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The principal advantages of using coiled tubing in a workover include the ability to (i) continue production from the well without interruption, thus reducing the risk of formation damage, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe in the case of a workover rig, which must be jointed and unjointed, (iii) direct fluids into a wellbore with more precision, allowing for improved stimulation fluid placement, (iv) provide a source of energy to power a downhole mud motor or manipulate down-hole tools and (v) enhance access to remote fields due to the smaller size and mobility of a coiled tubing unit.

As of December 31, 2022, we owned one coiled tubing unit capable of running 25,000 feet of two and five eighths inch coil rated at 15,000 pounds per square inch, or psi, two coiled tubing units capable of running 23,500 feet of two and three eighths inch coil rated at 15,000 psi, one coiled tubing unit capable of running 24,500 feet of two inch coil rated at 15,000 psi, two coiled tubing units capable of running 22,500 feet of two inch coil rated at 10,000 psi and one coiled tubing unit capable of running 20,500 feet of two and three eighths inch coil rated at 15,000 psi.

As of December 31, 2023, we owned two coiled tubing units capable of running 23,500 feet of two and three eighths inch coil rated at 15,000 psi, one coiled tubing unit capable of running 24,500 feet of two inch coil rated at 15,000 psi, two coiled tubing units capable of running 22,500 feet of two inch coil rated at 10,000 psi and one coiled tubing unit capable of running 20,500 feet of two and three eighths inch coil rated at 15,000 psi.

Pressure Control .

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Our pressure control services helped operators minimize the risk of such damage during completion activities.

As of December 31, 2022, we had a total of four nitrogen pumping units and seven fluid pumping units.

As of December 31, 2023, we had a total of four nitrogen pumping units and five fluid pumping units.

We provided pressure control services in the Eagle Ford Shale and the Permian Basin.

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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, 2022, we had seven fluid pumping units.

Five of these units are coiled tubing double pump units capable of output of up to eight barrels per minute, and are rated for pressures up to 15,000 psi.

As of December 31, 2023, we had five fluid pumping units.

Three of these units are coiled tubing double pump units capable of output of up to eight barrels per minute and are rated for pressures up to 15,000 psi.

Two of these units are quintuplex pump units capable of output of up to 15 barrels per minute and are rated for pressures up to 15,000 psi.

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Oil and Natural Gas Industry

The oil and natural gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including the domestic and international supply and demand for oil and natural gas, current and expected future prices for oil and natural gas and the perceived stability and sustainability of those prices, production depletion rates and the resultant levels of cash flows generated and allocated by exploration and production companies to their drilling, completion and related services and products budget.

The oil and natural gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and elsewhere), levels of customer demand, the availability of pipeline capacity and other conditions and factors, including global and national health concerns, that are beyond our control.

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 predominantly driven by the prices of oil and natural gas.

The levels of capital expenditures of our customers are driven by many factors, including the prices of oil and natural gas.

In March and April 2020, concurrent with the COVID-19 pandemic and quarantine orders in the U.S.

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In 2021, U.S.

oil production stabilized as commodity prices increased and demand for crude oil rebounded, which trend continued into 2022, with oil prices averaging $94.35 per barrel during that year.

As a result, we saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services during 2022 and we expect both pricing and utilization to remain at these levels throughout 2023 as a result of an increase in budgets for publicly traded exploration and production companies and elevated activity levels, driven by improved energy demand and strong commodity prices.

Concerns over potential recession or prolonged economic slowdown in the U.S.

and globally and the ongoing Russian/Ukrainian war, however, could have an adverse impact on the global energy markets and volatility of commodity prices.

oil production stabilized as commodity prices increased and demand for crude oil rebounded.

We saw improvements in the oilfield services industry and in both pricing and utilization of our well completion and drilling services during 2022.

Throughout 2023, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion activities for our customers, in particular, in the Utica and Marcellus Shale natural gas plays, and, as a result, reduced demand for our well completion services.

These factors have continued into the first quarter of 2024.

Despite this short-term softness, however, we are seeing indications that activity levels will begin to ramp back up in mid-2024, creating the opportunity to reactivate additional fleets, if appropriate.

The ongoing war in Ukraine and the recent Israel-Hamas war, however, could continue to have an adverse impact on the global energy markets and volatility of commodity prices, which could further adversely impact demand for our well completion services.

In response to market conditions, we temporarily shut down our cementing and acidizing operations and flowback operations beginning in July 2019, our contract drilling operations beginning in December 2019, our rig hauling operations beginning in April 2020, our coil tubing, pressure control and full service transportation operations beginning in July 2020 and our crude oil hauling operations beginning in July 2021.

We continue to monitor the market to determine if and when we can recommence these services.

Natural Sand Proppant Industry

We experienced a significant decline in demand of our sand proppant in the second half of 2019 and throughout 2020 as a result of completion activity falling due to lower oil demand and pricing, increased capital discipline by our customers, budget exhaustion and the COVID-19 pandemic.

As well drilling and completions began ramping back up in 2021, overall demand for frac sand increased from the 2020 levels, reaching approximately 93 million tons in 2021.

Activity and pricing continued to increase throughout 2022 as a result of increased commodity prices resulting in more drilling and completions activity and we expect both pricing and activity to remain at these levels throughout 2023.

Activity rebounded modestly in 2021 and continued to increase throughout 2022 as we saw an increase in the volume of sand sold.

Supply constraints from labor shortages negatively affected West Texas in-basin mine operations and increased demand for Northern White frac sand for the region in 2022.

Demand from oil and gas companies in Western Canada and the Marcellus Shale was also strong in 2022.

The increase in activity in 2022 resulted in an increase in demand and pricing for our sand, which continued throughout the first quarter of 2023.

Demand for our natural sand proppant was adversely impacted in the second quarter of 2023 by the wildfires in Canada, which hindered our ability to transport sand.

Notwithstanding the foregoing, our sand business remained resilient during the second quarter of 2023.

As discussed above, pricing for crude oil and natural gas declined from levels seen in 2022, which slowed down completion activities and adversely impacted demand for our sand proppant services in the second half of 2023.

We are beginning to see an uptick in orders for our sand in the first quarter of 2024.

Our proppant sand reserves consist of Northern White silica sand, giving us access to a range of high-quality sand grades meeting or exceeding all API specifications, including a mix between concentrations of coarse grades (20/40 and 30/50 mesh size) and finer grades (40/70 and 100 mesh size).

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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.

The low acid-solubility increases the integrity of Northern White frac sand relative to other proppants with higher acid-solubility, especially in shales where hydrogen sulfide and other acidic chemicals are co-mingled with the targeted hydrocarbons.

In addition, its crush resistant properties enable Northern White frac sand to be used in deeper drilling applications than the frac sand produced from many native mineral deposits.

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Energy Infrastructure Industry

The energy infrastructure industry involves the construction and maintenance of the electrical power grid, including, but not limited to, power generation, high voltage transmission lines, substations and low voltage distribution lines, all of which connect power generation facilities to end users.

The 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, substations and distribution networks and is determined by the level of expenditures of utility companies.

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, which impact the electrical grid.

These natural disasters include, but are not limited to, thunderstorms, ice storms, snow storms, tornadoes, hurricanes, earthquakes, wildfires and lightning strikes.

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.

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We believe their knowledge of our industries and business lines enhances our ability to provide innovative, client-focused and basin-specific customer service, which we also believe strengthens our relationships with our customers.

• Young fleet of equipment .

Our 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.

Three of our pressure pumping fleets with total combined horsepower of 132,500 were built in 2017.

• Fleet of equipment .

Our oilfield service fleet is predominantly comprised of equipment designed to optimize recovery from unconventional wells and our infrastructure service fleet is predominantly comprised of equipment designed to construct and repair electric transmission and distribution lines.

We believe that our fleet of quality equipment will allow us to provide a high level of service to our customers.

In addition, over the past three years we have converted 30 of our pressure pumping units to include DGB capabilities to meet recent shifts in customer demand and expect to convert 52 more units during 2023, subject to liquidity and supply chain constraints.

In addition, we have converted two fleets of our pressure

pumping units to include DGB capabilities to meet recent shifts in customer demand and expect to convert one additional fleet during 2024, subject to market conditions and liquidity requirements.

Our Business Strategy

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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.

• 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 2022, oil prices fluctuated between a low of $71.02 on December 9, 2022 and a high of $123.70 on March 8, 2022, and averaged $94.39 per barrel for the year.

We saw a significant increase in commodity pricing during 2022, resulting in higher utilization and increased margins for our pressure pumping and natural sand proppant divisions.

• Expand our energy infrastructure business.

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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.

During 2023, oil prices fluctuated between a low of $66.74 on March 17, 2023, and a high of $93.68 on September 27, 2023, and averaged $77.61 per barrel for the year.

We saw a decline in commodity pricing during 2023, resulting in lower utilization and margins for our oilfield services divisions.

• Maintain a conservative balance sheet.

We seek to maintain a conservative balance sheet, which allows us to better react to changes in commodity prices and related demand for our services, as well as overall market conditions.

During 2023, we reduced our outstanding debt balance by $40.7 million, from $83.5 million as of December 31, 2022 to $42.8 million as of December 31, 2023.

• Expand our services to meet expanding customer demand.

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• Expand through selected, accretive acquisitions.

To complement our organic growth and subject to our liquidity needs, we intend to pursue selected, accretive acquisitions of businesses and assets, primarily related to our infrastructure services, completion and production services and industrial based companies, that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence.

To complement our organic growth and subject to our liquidity needs, we intend to pursue selected, accretive acquisitions of businesses and assets, primarily related to our infrastructure

services, completion and production services and industrial based companies, that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence.

We believe this approach will help facilitate the strategic expansion of our customer base, geographic presence and service offerings.

We also believe that our industry contacts and those of Wexford Capital LP, or Wexford, our largest stockholder, may help us identify acquisition opportunities.

We 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.

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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, 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.

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, contract and directional drilling services and infrastructure engineering services.

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.

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Historically, we have used third-party contractors to provide remediation and spill response services when necessary to address spills that were beyond our containment capabilities.

None of these prior spills were significant, and we have not experienced any incidents, citations or legal proceeding relating to our hydraulic fracturing or crude hauling services for environmental concerns.

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.

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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.

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).

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.

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However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rules, and significantly reducing the waters subject to federal regulation under the Clean Water Act.

On August 30, 2021, a federal court struck down the replacement rule and, on December 30, 2022, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015.

Meanwhile, in October 2022, the Supreme Court heard oral arguments in a case addressing the proper test for determining whether wetlands are "waters of the United States".

As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act.

To the extent the rules expand the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

On August 30, 2021, a federal court struck down the replacement rule and, on January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015.

However on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the CWA.

On September 8, 2023, the EPA and the Corps published a final rule conforming their regulations to the Supreme Court decision.

These recent actions have provided some clarity.

However, to the extent the EPA and the Corps broadly interpret their jurisdiction and expand the range of properties subject to the Clean Water Act’s jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.

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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.

In August 2022, President Biden signed the Inflation Reduction Act of 2022 (the “IRA”) into law.

The IRA contains 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.

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.

The IRA could accelerate the transition of the economy away from the use of fossil fuels towards lower or zero carbon emissions alternatives, which could decrease demand for our well completion, natural sand proppant and other services related to the oil and natural gas industry.

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.

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The Paris Agreement went into effect on November 4, 2016.

The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions.

Although the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden issued an executive order on January 20, 2021 to rejoin the Paris Agreement, which went into effect on February 19, 2021.

On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its greenhouse gas emissions by 50 to 52 percent below 2005 levels in 2030.

In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and other world leaders made further commitments to reduce greenhouse gas emission, including reducing global methane emissions by at least 30% by 2030 to meet this objective.

More than 150 countries have now signed on to this pledge.

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.

Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely affect the oil and natural gas industry by reducing demand for hydrocarbons and by making it more expensive to develop and produce hydrocarbons, either of which could have a material adverse effect on future demand for our services.

The United States Environmental Protection Agency has proposed strict new methane emission regulations for certain oil and gas facilities.

The Inflation Reduction Act of 2022 establishes a charge on methane emissions above certain limits from the same facilities.

At this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

In addition, there have also been efforts in recent years to influence the investment community, including investment

advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves.

Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities,

operations and ability to access capital.

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.

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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.

However, on August 13, 2020, in response to an executive order by former President Trump to review and revise unduly burdensome regulations, the EPA amended the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether.

On June 30, 2021, President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments (with the exception of some technical changes) thereby reinstating the 2012 and 2016 New Source Performance standards.

The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards.

Additionally, on November 15, 2021, the EPA published a proposed rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries and prohibiting venting of natural gas in certain situations.

On December 6, 2022, the EPA published a supplemental proposal to strengthen the emission reduction requirements, which would, among other things, expand leak detection requirements and tighten flaring restrictions.

These new standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

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.

In July 2023, the Biden Administration also announced a new Cabinet-level task force aimed at detecting and cracking down on methane leaks.

These new standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

We cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

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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.

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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.

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.

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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.

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These rules, among other things, set forth siting and setback criteria, prescribe detailed construction and operational requirements, establish insurance and financial assurance requirements, and institute requirements for decommissioning.

As of January 2024, the ODNR Division of Oil and Gas Resources Management is updating sections of the Ohio Administrative Code that regulate oil and gas activity, including proposed changes to the provisions governing the design, construction, modification, and reclamation of well sites used to drill and produce horizontal oil and gas wells.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws.

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• 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.

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.

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Compliance with these laws and regulations has not had a material adverse effect on our operations or financial position.

Employees, Safety and Diversity

As of December 31, 2023, we had 733 full time employees.

The number of employees fluctuates depending on the current and expected demand for our services.

None of our employees are represented by labor unions or covered by any collective bargaining agreements.

We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full-time employees.

We view our employees as our greatest asset and actively recruit talented people regardless of gender or ethnic background.

We also promote diversity, inclusion and equal employment opportunities by evaluating and promoting employees based on skills and performance alone, while also seeking to attract and retain a diverse workforce and continuing to cultivate an inclusive and respectful work environment.

One of six of our current board members and director nominees is ethnically diverse.

Further, as of December 31, 2023, over 11% of our employees were women and 22 of 97 employees holding managerial and other key positions within the organization are women.

Also, over 11% of our employees self-identify as ethnic minorities as of December 31, 2023.

Further, we invest in the learning and development of our employees.

We strive to identify talent and to provide employees who demonstrate exceptional performance with opportunities and training to progress to higher levels within the organization.

We maintain a culture of safety, committed to the protection of the health and safety of our employees as well as preserving the environment and our relationships with the communities in which we operate.

We place a strong emphasis on the safe execution of our operations, including safety training for our employees.

We have a comprehensive approach to formulating and managing training requirements for our operational employees.

This includes periodic environmental, health and safety meetings, a combination of live in-person training and computer-based training tailored to specific job duties and operational activities, and comprehensive safety reference material.

In addition, our safety recognition program encourages employees throughout our organization to focus on conducting operations in accordance with our strict safety standards.

Further, we work closely with federal, state and local governments and community organizations to help ensure that our operations comply with legal requirements and community standards.

Lastly, when our employees identify a heightened safety risk, we respond quickly to mitigate the risk through communication, coordination and, if appropriate, a change in policy, procedures and training.

We believe that our customers select their operational partners based in part on the quality of their safety and compliance records, and therefore, we will continue to make investments in this area.

We also empower all personnel with stop-work authority (“SWA”) as a tool for helping ensure safety.

Our SWA policy empowers our employees to stop work whenever they identify unsafe work conditions.

When SWA is employed, operations cease until the risk is addressed and both

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

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• Failure by PREPA to pay the amounts owed to our infrastructure subsidiary Cobra for services performed would materially and adversely affect our financial condition, results of operations and cash flows.

• Our ability to generate sufficient cash in the next nine months necessary to repay or refinance our existing revolving credit facility at or prior to maturity is subject to a number of risks and uncertainties.

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

• We may experience losses in excess of our recorded reserves for receivables.

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

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

• Our revolving credit facility and term credit facility impose restrictions on us that may affect our ability to successfully operate our business.

• Volatility in the oil and natural gas markets has negatively impacted our business in the past, and could negatively impact our oilfield services business in the future.

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

• Our revolving credit facility provides, and any future credit facilities may provide, for fluctuating interest rates, which may increase or decrease our interest expense.

• Our revolving credit facility and term credit facility provide for fluctuating interest rates, which may increase or decrease our interest expense.

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

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• Changes in tax laws and regulations or adverse outcomes resulting from examination of our tax returns may adversely affect our business, results of operations, financial condition and cash flow.

• A cyber incident could occur and result in information theft or other loss, data corruption, operational disruption and/or financial loss.

• Cyber incidents or intrusions may result in information theft or other loss, data corruption, operational disruption and/or financial loss.

Risks Inherent to Our Common Stock

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• The declaration of dividends on our common stock is within the discretion of our board of directors, and there is no guarantee that we will pay any dividends in the future or at levels anticipated by our stockholders.

• Our ability to repurchase stock may be limited and no assurance can be given that we will be able to effectuate our stock repurchase program in the future at indicated levels or at all.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business