What changed in this filing

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Item 1. Business

2021-03-05 compared with 2020-06-22 · 114 added, 132 removed, 137 unchanged (64% of the section changed)

We are a growth‑oriented, Midland, Texas‑based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production (“E&P”) of North American unconventional oil and natural gas resources.

We are a Midland, Texas‑based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production (“E&P”) of North American unconventional oil and natural gas resources.

Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies.

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Changes to our customers’ well design, shale formations, operating conditions and new technology have resulted in continuous changes to the number of pumps that constitute a fleet.

As a result of the asymmetric nature of the number of pumps that constitute a fleet across our customer base, which we believe will continue to evolve, we view HHP to also be an appropriate metric to measure our available hydraulic fracturing capacity.

At the beginning of the year, our fleet size was 28 conventional hydraulic fracturing fleets.

During 2019, we reconfigured our existing fleet size to 24 conventional fleets with the objective of increasing our HHP per fleet, and we subsequently purchased 54,000 HHP of new DuraStim® hydraulic pumps, bringing our total HHP at December 31, 2019 to 1,469,000 HHP.

Our total HHP as of December 31, 2019 was comprised of 1,415,000 HHP of conventional HHP and 54,000 HHP of our newly purchased DuraStim® hydraulic fracturing technology.

With the continuous evaluation and changes to the number of pumps or HHP that constitute a fleet, we believe that our available fleet capacity could decline as we reconfigure our fleets to increase active HHP and back up HHP based on our customers’ operational needs.

In 2019, we entered into a purchase commitment for 108,000 HHP DuraStim® hydraulic fracturing pumps.

We believe that one DuraStim® fleet could require between 6 to 9 frac pumps or 36,000 to 54,000 HHP per fleet, depending on the shale formation in which it operates and the customer’s well design.

The first DuraStim® hydraulic fracturing pumps were delivered in December 2019 and the remaining DuraStim® hydraulic fracturing pumps are expected to be delivered in 2020.

We also have an option to purchase up to three additional DuraStim® fleets in the future through April 2021.

We believe the DuraStim® hydraulic fracturing pump technology could represent the future of our industry and is designed to drive down well costs for our customers while improving safety and the useful life of the equipment and reducing environmental impact.

The DuraStim® technology is powered by electricity.

We purchased two gas turbines to provide electrical power for our DuraStim® fleets.

As a result of the asymmetric nature of the number of pumps that constitute a fleet across our customer base and competitors, which we believe will continue to evolve, we view HHP to be an appropriate metric to measure our available hydraulic fracturing capacity.

Our total available HHP at December 31, 2020 was 1,373,000 HHP (excluding approximately 150,000 HHP we are in the process of permanently retiring), which was comprised of 1,265,000 HHP of conventional Tier II equipment and 108,000 HHP of our new DuraStim® electric powered hydraulic fracturing equipment.

In addition, we have committed to purchase 50,000 HHP of Tier IV Dynamic Gas Blending (“DGB”) dual fuel equipment, that is expected to be delivered before the end of the first half of 2021.

Our Tier IV DGB equipment could be powered by either diesel or natural gas, an improvement from Tier II conventional equipment that can only be powered with diesel.

With the industry transition to lower emissions equipment and changes to the number of pumps or HHP that constitute a fleet, we believe that our available fleet capacity could decline as we reconfigure our fleets to increase active HHP and backup HHP based on our customers’ operational needs or as we retire and replace conventional Tier II equipment.

In light of the energy industry transition to lower emissions equipment, the Company made a strategic decision to permanently retire approximately 150,000 HHP of its existing conventional Tier II pressure pumping equipment.

In 2019, we entered into a purchase commitment for 108,000 HHP DuraStim® electric powered hydraulic fracturing equipment.

Our DuraStim® equipment is still being tested and has only been deployed to our customers’ wellsites on a limited scale.

As we continue with our testing of the equipment, the number of DuraStim® pumps that constitute a fleet will depend on a combination of factors, including the ultimate operating performance of DuraStim® pumps following the completion of testing, the particular shale formation where a well is completed, customer service requirements and job design.

The Company has set a goal to commercialize its first DuraStim® fleet to our customer wellsites in the second half of 2021.

We also have an option to purchase up to an additional 108,000 HHP of DuraStim® hydraulic fracturing equipment in the future through July 31, 2022.

We currently have gas turbines to provide electrical power to our DuraStim® fleet.

The electrical power sources for future DuraStim® fleets are still being evaluated and could either be supplied by the Company, customers or a third-party supplier.

All of our hydraulic fracturing fleets have been designed to handle the most challenging Permian Basin operating conditions and the region’s increasingly high‑intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well.

In addition to our core pressure pumping segment operations, which includes our cementing operations, we also offer a suite of complementary well completion and production services, including coiled tubing and other services.

All of our hydraulic fracturing fleets have been designed to handle the most challenging Permian Basin operating conditions and the region’s increasingly high‑intensity well completions, which are characterized by longer horizontal wellbores, more fractured stages, increased number of wells per pad and increasing amounts of proppant per well.

In addition to our core pressure pumping segment operations, which consist of our hydraulic fracturing and cementing operations, we also offer a suite of complementary well completion and production services, including coiled tubing and other services.

We believe these complementary services create operational efficiencies for our customers and could allow us to capture a greater portion of their capital spending across the lifecycle of a well.

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In addition, global crude oil prices experienced a collapse starting in early March 2020 as a direct result of failed negotiations between OPEC and Russia.

In response to the global economic slowdown, OPEC had recommended a decrease in production levels in order to accommodate reduced demand.

rejected the recommendation of OPEC as a concession to U.S.

After the failure to reach an agreement, Saudi Arabia, a dominant member of OPEC, and other Persian Gulf OPEC members announced intentions to increase production and offer price discounts to buyers in certain geographic regions.

As the breadth of the COVID-19 health crisis expanded throughout the month of March 2020 and governmental authorities implemented more restrictive measures to limit person-to-person contact, global economic activity continued to decline commensurately.

The associated impact on the energy industry has been adverse and continued to be exacerbated by the unresolved conflict regarding production.

In the second week of April 2020, OPEC+ reconvened to discuss the matter of production cuts in light of unprecedented disruption and supply and demand imbalances that expanded since the failed negotiations in early March 2020.

Tentative agreements were reached to cut production by up to 10 million barrels of oil per day, or BOPD, with allocations to be made among the OPEC+ participants.

Some of these production cuts went into effect in the first half of May 2020, however, commodity prices remain depressed as a result of an increasingly utilized global storage network and near-term demand loss attributable to the COVID-19 health crisis and related economic slowdown.

The combined effect of COVID-19 and the energy industry disruptions led to a decline in WTI crude oil prices of approximately 67 percent from the beginning of January 2020, when prices were approximately $62 per barrel, through the end of March 2020, when they were just above $20 per barrel.

Overall crude oil price volatility has continued despite apparent agreement among OPEC+ regarding production cuts and as of June 17, 2020, the WTI price for a barrel of crude oil was approximately $38.

Despite a significant decline in drilling and completion activity by U.S.

producers starting in mid-March 2020, domestic supply continues to exceed demand which has led to significant operational stress with respect to capacity limitations associated with storage, pipeline and refining infrastructure, particularly within the Gulf Coast region.

The combined effect of the aforementioned factors is anticipated to have a continuing adverse impact on the industry in general and our operations specifically.

As the breadth of the COVID-19 health crisis expanded throughout the month of March 2020 and governmental

authorities implemented more restrictive measures to limit person-to-person contact, global economic activity continued to decline commensurately.

The associated impact on the energy industry has been adverse and continued to be exacerbated by the depressed demand in the energy sector and uncertainty in global production levels.

In response to the global economic slowdown and depressed demand in the oil and gas industry, OPEC+ has made adjustments to production levels with the objective of rebalancing the energy market.

After the March 2020 failed negotiations, OPEC+ subsequently agreed to cut production by 7.7 million barrels of oil per day, or BOPD.

In January 2021, OPEC+ reconvened to discuss the matter of production cuts in light of unprecedented disruption and supply and demand imbalances.

Agreements were reached to gradually increase production by 0.5 million BOPD, starting in January 2021, and adjusting the production reduction from 7.7 million BOPD to 7.2 million BOPD.

OPEC+ members have shown compliance with previously agreed upon production levels, and we have seen recovery in crude oil prices from its low point in 2020.

The combined effect of COVID-19 and the energy industry disruptions led to a decline in West Texas Intermediate (“WTI”) crude oil prices of approximately 67 percent from the beginning of January 2020, when prices were approximately $62 per barrel, through the end of March 2020, when they were just above $20 per barrel.

Overall, with OPEC+ managing production levels and with the development and distribution of COVID-19 vaccines, there has been gradual recovery in crude oil prices from t he low point in March 2020.

As of March 3, 2021, the WTI price for a barrel of crude oil was approximately $62, a significant increase from its low point in 2020.

However, with the uncertainty in the global market resulting from the COVID-19 pandemic, the r isk that currently developed vaccines may not be successful in preventing the COVID-19 virus or the outbreak of a new virus, the global demand for crude oil could continue to be depressed and crude oil prices could decline.

In order to mitigate the impact of COVID-19 and the economic effects of the unprecedented decline in economic activity and global energy markets, we undertook several actions since March 2020 in support of the efficient continuity of our operations.

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hydraulic fracturing, cementing, coiled tubing, flowback and drilling.

For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment:

pressure pumping.

For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into one reportable segment—pressure pumping.

Our coiled tubing, flowback, and drilling operating segments and corporate administrative expense are aggregated into our “All Other” reportable segment.

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We have significant expertise in multi‑stage fracturing of horizontal oil‑producing wells in unconventional geological formations.

We took delivery of 54,000 HHP of new DuraStim® hydraulic fracturing pumps in December 2019, bringing our total fleet capacity to 1,469,000 HHP as of December 31, 2019 .

Our DuraStim® hydraulic fracturing equipment has been tested on a limited scale basis with certain of our customers.

The Company has set a goal to commercialize its first DuraStim® fleet to our customers’ wellsites in the second half of 2021.

The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation.

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We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services.

We also refer to all of our fracturing units, other equipment and vehicles necessary to perform a fracturing job as

a “fleet” and the personnel assigned to each fleet as a “crew.” Our conventional hydraulic fracturing units consist primarily of a high pressure hydraulic pump, diesel engine, transmission and various hoses, valves, tanks and other supporting equipment like blenders, irons and data vans.

The new DuraStim® hydraulic fracturing fleet is powered by electricity and the electrical power equipment could either be provided by us or our customers.

We also refer to all of our fracturing units, other equipment and vehicles necessary to perform a fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” On average, one conventional Tier II hydraulic fracturing

fleet consists of approximately 50,000 HHP, depending on job design and customer demand.

Our conventional Tier II hydraulic fracturing units consist primarily of a high pressure hydraulic pump, diesel engine, transmission and various hoses, valves, tanks and other supporting equipment like blenders, irons and datavans.

Our DuraStim® hydraulic fracturing fleet can be powered by turbines, generators or similar equipment that could generate electricity.

We provide dedicated equipment, personnel and services that are tailored to meet each of our customer’s needs.

Each fleet has a designated team of personnel, which allows us to provide responsive and customized services, such as project design, proppant and other consumables procurement, real‑time data provision and post‑completion analysis for each of our jobs.

Many of our hydraulic fracturing fleets and associated personnel have continuously worked with the same customer for the past several years promoting deep relationships and a high degree of coordination and visibility into future customer activity levels.

Furthermore, in light of our substantial market presence and historically high fleet utilization levels, we have established a variety of entrenched relationships with key equipment, sand and other downhole consumable suppliers.

These strategic relationships ensure ready access to equipment, parts and materials on a timely and economic basis and allow our dedicated procurement logistics team to ensure consistently safe and reliable operations.

Many of our hydraulic fracturing fleets and associated personnel have worked continuously with the same customer for the past several years promoting deep relationships and a high degree of coordination and visibility into future customer activity levels.

Furthermore, in light of our substantial market presence and historically high fleet utilization levels, we have established a variety of trusted relationships with key equipment, sand and other downhole consumable suppliers.

These strategic relationships ensure ready access to equipment, parts and materials on a timely and economic basis and allow our dedicated procurement and logistics team to ensure consistently safe and reliable operations.

We provide cementing services for completion of new wells and remedial work on existing wells.

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Cementing provides isolation between fluid zones behind the casing to minimize potential damage to hydrocarbon bearing formations or the integrity of freshwater aquifers, and provides structural integrity for the casing by securing it to the earth.

Cementing is also done when recompleting wells, where one zone is plugged and another is opened.

As of December 31, 2019 , we had a total of 25 cementing units.

Cementing is also done when re-completing wells, where one zone is plugged and another is opened.

We believe that our cementing segment provides an organic growth opportunity for us to expand our service offerings within our existing customer base.

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It is wound or coiled on a truck‑mounted reel for onshore applications.

Due to its small diameter, 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.

The principal advantages of using coiled tubing 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 used with 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 motor or manipulate down‑hole tools and (v) enhance access to remote fields due to the smaller size and mobility.

As of December 31, 2019 , we had a total of 9 coiled tubing units of various sizes.

Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services (including drillout of plugs) to enhance the flow of oil or natural gas.

The principal advantages of using coiled tubing 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 used with 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 motor or manipulate downhole tools and (v) enhance access to remote fields due to the smaller size and mobility.

Flowback Services

Our flowback services consist of production testing, solids control and hydrostatic testing.

Our flowback services consisted of production testing, solids control and hydrostatic testing.

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

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

We provide flowback services in the Permian Basin and mid‑continent markets.

Our flowback business segment has continued to decline in profitability over the years, and as a result, the Company shut down its flowback operations in 2020 and disposed of the assets.

Our vertical drilling assets in our drilling segment have been idled since 2016.

The Company is considering strategic alternatives for the use of its drilling rigs including exploring options to dispose of the remaining drilling rigs and ancillary assets.

If the market for vertical drilling does not improve and the equipment continues to be idled, the estimated fair value for the drilling rigs may decline, thus resulting in future additional impairment charges.

Competitive Strengths

Our primary business objective is to serve as a strategic long-term partner for our customers.

We achieve this objective by providing reliable, high‑quality services that are tailored to our customers’ needs and synchronized with their well development programs.

This alignment assists our customers in optimizing the long‑term development of their unconventional resources.

We believe that the following competitive strengths differentiate us from our peers and uniquely position us to achieve our primary business objective.

Strong market position in the Permian Basin.

We believe we are one of the largest hydraulic fracturing providers by HHP in the Permian Basin, which is one of the most prolific oil producing areas in the United States.

Our longstanding customer relationships and substantial Permian Basin market presence uniquely position us to maintain our market position and grow as the basin is developed in the future.

The Permian Basin is a mature, liquids‑rich basin with well-known geology and a large, exploitable resource base that delivers attractive E&P producer economics.

As a result of its significant size, coupled with the presence of multiple prospective geologic benches and other favorable characteristics, the Permian Basin has become widely recognized as one of the most attractive and economic oil resources in North America.

Our operational focus has historically been in the Permian Basin’s Midland sub‑basin in support of our customers’ core operations.

More recently, however, many of our customers have made sizeable acquisitions in the Delaware sub-basin, and we have expanded our services into the Delaware sub-basin to help develop their acreage.

Further, we believe that we are uniquely positioned to capture a large addressable growth opportunity as the basin develops.

For the foreseeable future, we expect both the Midland sub-basin and the Delaware sub-basin to continue to command a disproportionate share of future North American E&P spending.

Deep relationships and operational alignment with high‑quality, Permian Basin‑focused customers.

Our deep local roots, operational expertise and commitment to safe and reliable service have allowed us to cultivate longstanding customer relationships with the most active and well‑capitalized Permian Basin operators.

Many of our current customers have worked with us since our inception and have integrated our fleet scheduling with their well development programs.

We have a long-term partnership agreement with one customer, an E&P company focused in the Permian Basin, to continue to provide pressure pumping and other complementary services for up to 10 years.

This relationship differentiates us from our peers.

This high degree of operational alignment and partnership with our customers has allowed us to maintain relatively high utilization rates over time compared to our peers.

If our customers increase activity levels, we expect to continue to leverage our strong relationships to keep our fleets utilized.

Proven cross‑cycle financial performance.

Over the past several years, we have maintained high cross‑cycle fleet utilization rates.

From late 2017 through 2018 our fleets were consistently fully utilized.

In 2019, following a decline in certain of our customers’ operations in the last quarter of 2019, our fleets utilization decreased slightly, and our utilization has decreased dramatically in 2020 as a result of COVID-19 and related matters.

Historically, our consistent track record of steady growth, coupled with our ability to quickly deploy new HHP on a dedicated and fully utilized basis, has resulted in revenue growth across the industry’s cycles.

We believe that we will be able to continue to operate more efficiently than our competitors while preserving attractive profitability and cash flows as a result of our differentiated service offerings and wellsite efficiencies.

Furthermore, we believe that our philosophy of maintaining modest financial leverage and a healthy balance sheet has left us more conservatively capitalized than most of our peers.

We expect that improving market fundamentals, our superior execution and our customer‑focused approach should continue to result in strong financial performance.

Seasoned management and operating team.

We have a seasoned executive management team, with our senior members contributing more than 100 years of collective industry and financial experience.

We believe their deep roots and relationships throughout the West Texas community, provide a meaningful competitive advantage for our business.

In addition, our management team has assembled a loyal group of highly‑motivated and talented managers and field personnel, and we have had minimal manager‑level turnover in our core service divisions

over the past several years.

We employ a balanced decision‑making structure that empowers managerial and field personnel to work directly with customers to develop solutions while leveraging senior management’s oversight.

This collaborative approach fosters strong customer links at all levels of the organization and effectively institutionalizes customer relationships beyond the executive suite.

Our strategy is to:

Capture an increasing share of demand for hydraulic fracturing services in the Permian Basin.

We intend to continue to position ourselves as a Permian Basin‑focused hydraulic fracturing business, as we believe the Permian Basin hydraulic fracturing market offers supportive long‑term growth fundamentals.

These fundamentals are characterized by increased demand for our HHP and well completion intensity levels.

We have historically operated at a high utilization relative to our peers, and we believe we are strategically positioned to deploy our idle horse-power if overall market condition and demand for pressure pumping services increases.

Capitalize on improving efficiency gains.

We intend to continue to work with our customers and vendors to improve our operational efficiencies and enhance our profitability.

We believe that improving our efficiencies will result in greater revenue and enhanced profitability as fixed costs are spread over a broader revenue base.

Cross‑sell our complementary services.

In addition to our hydraulic fracturing services, we offer a broad range of complementary services in support of our customers’ development activities, including cementing and coiled tubing.

These complementary services create operational efficiencies for our customers, and allow us to capture a greater percentage of their capital spending across the lifecycle of an unconventional well.

We believe that, if our customers increase spending levels, we are well positioned to continue cross‑selling and growing our complementary service offerings.

Maintain financial stability and flexibility to pursue growth opportunities.

Consistent with our historical practices, we plan to continue to maintain a conservative balance sheet, which will allow us to better react to potential changes in industry and market conditions and opportunistically grow our business.

In the near term, we intend to continue our past practice of aligning our growth capital expenditures with visible customer demand by strategically deploying new equipment on a dedicated basis in response to inbound customer requests.

We will also selectively evaluate potential strategic acquisitions that increase our scale and capabilities or diversify our operations.

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

Historically, we provided flowback services in the Permian Basin and Mid‑Continent markets.

In March 2020, the Company shut down its flowback operations and disposed of all the assets.

Our vertical drilling assets in our drilling segment have been idled since 2016, and in September 2020, the Company shut down its drilling operations and disposed of all of its drilling rigs and ancillary assets.

Our Customers

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For the year ended December 31, 2020, Pioneer Natural Resources USA Inc.

(“Pioneer”), XTO Energy Inc., CrownQuest Operating, LLC, accounted for 25.5% , 20.9% , and 13.2% , respectively, of total revenue.

(“Pioneer”) and XTO Energy Inc.

accounted for 42.5% and 20.3%, respectively, of total revenue.

No other customer accounted for more than 10% of our total revenue for the year ended December 31, 2020.

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To be successful, an oilfield services company must provide services that meet the specific needs of oil and natural gas E&P companies at competitive prices.

Competitive factors impacting sales of our services are price, reputation, technical expertise, service and equipment quality, and health and safety standards.

Competitive factors impacting sales of our services are price, reputation, technical expertise, emissions profile, service and equipment design and quality, and health and safety standards.

Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies’ criteria in choosing a service provider.

While we seek to price our services competitively, we believe many of our customers elect to work with us based on our deep local roots, operational expertise, equipment quality, ability to handle the most complex Permian Basin well completions and commitment to safety and reliability.

However, we have recently observed the energy industry and our customers shift to lower emissions equipment, which we believe will be an increasingly important factor in an E&P company’s selection of a service provider.

While we seek to price our services competitively, we believe many of our customers elect to work with us based on our operational efficiencies, productivity, equipment quality, commitment to safety and the ability of our people to handle the most complex Permian Basin well completions.

We provide our services primarily in the Permian Basin, and we compete against different companies in each service and product line we offer.

Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies.

Our major competitors for hydraulic fracturing services include Nextier Oilfield Solutions Inc., Halliburton Company, Patterson‑UTI Energy Inc., RPC, Inc., Schlumberger Limited, Liberty Oilfield Services, FTS International, Inc., Superior Energy Services and a number of locally oriented businesses.

Our major competitors for hydraulic fracturing services include Halliburton Company, Liberty Oilfield Services Inc., Nextier Oilfield Solutions Inc., Patterson‑UTI Energy Inc., RPC, Inc., and FTS International, Inc.

and a number of private and locally-oriented businesses.

Our results of operations have historically reflected seasonal tendencies, generally in the fourth quarter, relating to the conclusion of our customers’ annual capital expenditure budgets, the holidays and inclement winter weather during which we may experience declines in our operating results.

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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, umbrella liability, 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 automobile, commercial property, umbrella liability, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry.

Further, we have pollution legal liability coverage for our business entities, which would cover, among other things, third party liability and costs of clean up relating to environmental contamination on our premises while our equipment is in transit and on our customers’ job site.

With respect to our hydraulic fracturing operations, coverage would be available under our pollution legal liability policy for any surface or subsurface environmental clean‑up and liability to third parties arising from any surface or subsurface contamination.

With respect to our

hydraulic fracturing operations, coverage would be available under our pollution legal liability 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 hydraulic fracturing services.

We maintain director and officer insurance;

however, our insurance coverage is subject to certain exclusions (including, for example, any required SEC disgorgement or penalties) and we are responsible for meeting certain deductibles under the policies.

Moreover, we cannot assure you that our insurance coverage will adequately protect us from claims made in the Logan Lawsuit, the Shareholder Derivative Lawsuit, the SEC investigation or any future claims.

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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Changes in environmental, health and safety laws and regulations occur frequently, and any changes that result in more stringent and costly requirements could materially adversely affect our operations and financial position.

We have not experienced any material adverse effect from compliance with these requirements, however, this trend may not continue in the future.

For example, following the election of President Biden and Democratic control in both houses of Congress, it is possible that our operations may be subject to greater environmental, health and safety restrictions, particularly with regards to hydraulic fracturing, permitting and greenhouse gases (“GHG”) emissions.

We have not experienced any material adverse effect from compliance with current requirements;

however, this trend may not continue in the future.

Below is an overview of some of the more significant environmental, health and safety requirements with which we must comply.

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Liability for the costs of removing or remediating previously disposed wastes or contamination, damages to natural resources, the costs of conducting certain health studies, amongst other things, is strict and joint and several.

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 laws.

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However, following the U.S.

Supreme Court finding that greenhouse gases (“GHG”) emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation ("DOT"), implementing GHG emissions limits on vehicles manufactured for operation in the United States.

Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of certain pollutant from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the Department of Transportation ("DOT"), implementing GHG emissions limits on vehicles manufactured for operation in the United States.

For example, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities, otherwise known as Subpart OOOOa.

Following the change in administration, there have been attempts to modify these regulations, and litigation is ongoing.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.

At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions through non-binding, individually determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by some candidates seeking the office of the President of the United States in 2020.

Some of these pledges have included calls to ban hydraulic fracturing, which could adversely impact our operations.

Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result.

The EPA finalized amendments to the 2016 standards in September 2020 that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities.

However, several lawsuits have been filed challenging these amendments, and President Biden has called for the issuance of regulations that would suspend, revise or rescind the September 2020 rule and the introduction of new or more stringent emissions standards for new, modified and existing oil and gas facilities.

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas such as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.

At the international level, there is an agreement, the United Nations-sponsored “Paris Agreement,” that requires nations to submit non-binding emissions reduction targets every five years after 2020.

Although the United States had previously withdrawn from the Paris Agreement, President Biden has signed executive orders on his first day in office recommitting the United States to the agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement.

However, the impacts of these executive orders, and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement, are unclear at this time.

On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry and an increased emphasis on climate-related risk across government agencies and economic sectors.

The executive order also suspends the issuance of new leases for oil and gas development on federal land;

for more information, see our regulatory disclosure titled “Regulation of Hydraulic Fracturing and Related Activities.” Other actions that the Biden Administration may take include the imposition of more restrictive requirements for the development of pipeline infrastructure or liquefied natural gas export facilities or more restrictive GHG emissions limitations for oil and gas facilities.

Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or that such companies have been aware of the adverse effects of climate change but failed to adequately disclose those impacts to their investors or customers.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products.

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For example, the dunes sagebrush lizard, which is found only in the active and semi-stable shinnery oak dunes of southeastern New Mexico and adjacent portions of Texas (including areas where our customers operate), was a candidate species for listing under the ESA by the FWS for many years.

As a result of a recent settlement with the environmental groups, the FWS has agreed to act on a petition to list the dunes sagebrush lizard by June 30, 2020, which would result in a formal one-year review to consider listing the species if the petition is accepted.

To the extent any protections are implemented for this or any other species, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.

As a result of a recent settlement with the environmental groups, the FWS, in July 2020, acted on a petition to list the dunes sagebrush lizard finding sufficient information to warrant a formal one-year review to consider listing the species.

While the listing review is ongoing, FWS has also solicited comments on a proposed conservation agreement that would implement certain protective practices for the species and authorize incidental take of the species resulting from certain covered activities, including exploration and development of oil and gas fields.

However, to the extent any protections are implemented for this or any other species, it could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.

Regulation of Hydraulic Fracturing and Related Activities.

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However, federal agencies have asserted regulatory authority over certain aspects of the process.

For example, the EPA has previously issued a series of rules under

the CAA that establish new emission control requirements for certain oil and natural gas production and natural gas processing operations and associated equipment.

There have been several attempts to modify or rescind such regulations and litigation is ongoing.

For example, the EPA has previously issued a series of rules under the CAA that establish new emission control requirements for certain oil and natural gas production and natural gas processing operations and associated equipment.

Separately, the Bureau of Land Management (“BLM”) previously finalized a rule governing hydraulic fracturing on federal lands, but in June 2016, a federal district court judge in Wyoming struck down the final rule, finding that the BLM lacked congressional authority to promulgate the rule.

While this ruling was initially challenged, in December 2017, the BLM published a rulemaking to rescind the final rule and reinstate the regulations that existed immediately before the published effective date of the rule.

Further, legislation to amend the Safe Drinking Water Act 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, have previously been proposed in Congress.

Although several of these rulemakings have been rescinded or modified, new or more stringent regulations may be promulgated by the Biden administration.

For example, on January 20, the Biden Administration’s Department of the Interior (“DOI”) issued an order that temporarily suspended the issuance of any fossil fuel authorizations, including leases and permits, for a period of 60 days, and President Biden subsequently issued a longer suspension on the issuance of new oil and gas leases on federal land, pending a review of current practices.

Although the orders do not limit existing operations under valid leases, any restrictions for new or existing production activities on federal land could adversely impact our customers’ operations, and consequently demand for our services.

Further, legislation to amend the Safe Drinking Water Act 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, have previously been proposed in Congress.

Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

Federal and state governments have also investigated whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas.

For example, the United States Geological Survey identified eight states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, Arkansas, Ohio and Alabama.

In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells.

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The Texas Railroad Commission has adopted similar rules.

In addition, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.

However, the EPA has imposed no regulatory limits as a result of this study.

Increased regulation of hydraulic fracturing and related activities (whether as a result of the EPA study results or resulting from other factors) could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements.

Increased regulation of hydraulic fracturing and related activities could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements.

New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.

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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.

As of December 31, 2019 , we employed approximately 2,200 people.

None of our employees are represented by labor unions or subject to collective bargaining agreements.

Primarily as a result of the significant decline in oil prices and our customers’ rapid response to reduce their drilling and completion activities, we have implemented significant reductions in our workforce since December 31, 2019 .

As of June 10, 2020, we had approximately 700 employees.

Human Capital

Our employees are our key asset.

Our primary human capital management objectives are to effectively engage, develop, retain and reward our employees.

As of December 31, 2020, we employed approximately 1,100 people, none of which are unionized.

Of the total population over 80% of our headcount worked for our pressure pumping segment.

Our employees are a key component of our ability to attract and retain customers as a result of their operational excellence in the field.

Some examples of significant programs and initiatives that are focused to attract, develop and retain our diverse workforce include:

• Diversity and inclusion.

We believe that in order to attract and retain talent with the skill sets and expertise required to maximize our operational efficiencies across all levels in the Company, it is in our best interest to attempt to recruit and develop a diverse team and create a culture that is inclusive and provides equal opportunities for hiring and advancement for all employees and prospective employees.

Some examples of this effort include;

◦ a commitment to conducting business in a manner that respects all human rights in compliance within the requirements of applicable laws;

◦ efforts to promote and encourage respect for human rights and fundamental freedoms for all without distinctions of any kind such as race, color, sex, language, religion, political or other opinions;

◦ working in partnership with personnel, business parties and other parties directly linked to our operations that share our commitment to these same principles;

◦ efforts in our employment practices, including through our code of conduct, our equal employment opportunity employer policy, and our anti-harassment policy;

◦ to make it possible for grievances regarding health and safety to be addressed early and remediated directly, in confidence and without fear of retaliation;

the Company provides an anonymous whistleblower hotline that is promoted internally and accessible from our intranet and internet.

• Training and Safety.

We offer in-depth, role-appropriate safety training upon hiring and as part of the continuous development of our employees.

The safety of our employees, our customers, and the communities in which we operate is paramount.

We track and evaluate safety incidents at wellsites and offices, and if an accident does occur, we take actions to mitigate similar incidents from reoccurring in the future.

The Company incentivizes employees to focus on conducting operations in accordance with our strict safety standards and encourages employees to immediately report any breach of safety protocol.

Twenty percent of our executive officers’ annual target bonuses under the 2020 annual incentive program were based upon the Company’s achievement of certain safety goals, including a target total recordable incident rate of less than one.

• Health and Wellness.

Our employee benefit offerings are designed to meet the varied and evolving needs of a diverse workforce across the Company and we believe are consistent with those provided by our peer companies with which we compete for talent.

The Company provides employees with the ability to participate in health and welfare plans, including medical, dental, life, accidental death and dismemberment and short-term and long-term disability insurance plans.

In 2020, we made the following adjustments to address the COVID-19 pandemic;

◦ instituted a remote work environment to the extent feasible to help protect our workforce from exposure to COVID-19 by limiting physical contact as much as possible;

◦ limited visitors to our offices and other work locations and encouraged all employees and visitors to wear masks at our offices and other work locations;

◦ provided coverage for COVID-19 testing and vaccination under the Company’s medical plan at no cost to our employees.

Availability of Filings

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, are made available free of charge on our internet web site at www.propetroservices.com , as soon as reasonably practicable after we have electronically filed the material with, or

furnished it to, the SEC.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our internet web site at www.propetroservices.com, as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC.

The SEC maintains an internet site that contains our reports, proxy and information statements and our other SEC filings.

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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