What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2022-02-25 compared with 2021-03-05 · 172 added, 196 removed, 272 unchanged (57% of the section changed)

4 unchanged sentences

Basis of Presentation

This discussion of our results of operations omits our results of operations for the year ended December 31, 2018 and the comparison of our results of operations for the years ended December 31, 2019 and 2018, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on June 22, 2020.

This discussion of our results of operations omits our results of operations for the year ended December 31, 2019 and the comparison of our results of operations for the years ended December 31, 2020 and 2019, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on March 5, 2021.

Unless otherwise indicated, references in this " Management’s Discussion and Analysis of Financial Condition and Results of Operations " to " ProPetro Holding Corp., " " the Company, " " we, " " our, " " us " or like terms refer to ProPetro Holding Corp.

and its subsidiary.

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, or 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 E&P of North American 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.

The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of hydraulic fracturing services in the region by hydraulic horsepower.

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 and competitors, which we believe will continue to evolve, we view HHP to be an appropriate metric to measure our available hydraulic fracturing capacity.

On average, one conventional Tier II hydraulic fracturing fleet consists of approximately 50,000 HHP, depending on job design and customer demand.

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® hydraulic fracturing equipment.

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

With the industry transition to lower emission equipment and changes to the number of pumps or HHP that constitute a fleet, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and back up HHP at the wellsites based on our customers’ and 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 .

As a result of the Company’s plan to retire 150,000 HHP during the year ended December 31, 2020, we recorded an impairment expense of approximately $21.3 million.

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

The Company has set a goal to commercialize its first DuraStim® hydraulic

fracturing equipment 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.

The DuraStim® equipment is powered by electricity.

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 be supplied by the Company, customers or a third-party supplier.

Our total available HHP at December 31, 2021 was 1,423,000 HHP, which was comprised of 90,000 HHP of our Tier IV DGB equipment, 1,225,000 HHP of conventional Tier II equipment and 108,000 HHP of our DuraStim® electric hydraulic fracturing equipment.

Our fleet could range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsites.

With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at the wellsites.

In September 2021, we placed an order with our equipment manufacturers for 125,000 HHP of Tier IV DGB equipment for additional conversions, which we expect to be delivered at different times through the first half of 2022.

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

In addition to DuraStim® fleets, we are also evaluating other electric and alternative pressure pumping solutions.

In December 2021, we disposed of our two gas turbines initially purchased to provide electrical power to our DuraStim® fleets but as determined they were an inefficient power solution in the field.

In the future, we may lease electrical power equipment from a third party or rely on our customers to provide power solutions for our electric equipment.

Our substantial market presence in the Permian Basin positions us well to capitalize on drilling and completion activity in the region.

Primarily, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have operated.

However, we have recently increased our operations in the Delaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers.

Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.

Through our pressure pumping segment (which also includes our cementing operations), we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin.

Our hydraulic fracturing fleet has been designed to handle the operating conditions commonly utilized in the Permian Basin and the region's increasingly high-intensity well completions (including Simul-Frac, which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more 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 coiled tubing services.

Through our coiled tubing services segment, we seek to create operational efficiencies for our customers, which could allow us to capture a greater portion of their capital spending across the lifecycle of a well.

Pioneer Pressure Pumping Acquisition

5 unchanged sentences

Pursuant to the Pioneer Services Agreement, the Company is entitled to receive compensation if Pioneer were to idle committed fleets ("idle fees");

however, we are first required to use all economically reasonable effort to deploy the idled fleets to another customer.

however, we are first required to use all economically reasonable efforts to deploy the idled fleets to another customer.

At the present, we have eight fleets committed to Pioneer.

During times when there is a significant reduction in overall demand for our services, the idle fees could represent a material portion of our revenues.

While management believes our relationship with Pioneer will continue beyond December 31, 2022, if Pioneer elects to terminate the Pioneer Services Agreement effective December 31, 2022, or seeks to renegotiate the terms on which we provide services to Pioneer, it could have a material adverse effect on our financial condition, results of operations and cash flows.

While management believes our relationship with Pioneer will continue beyond December 31, 2022, if Pioneer elects to terminate the Pioneer Services Agreement effective December 31, 2022, or seeks to renegotiate the terms on which we provide services to Pioneer, it could have a material adverse effect on our future financial condition, results of operations and cash flows.

Commodity Price and Other Economic Conditions

The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other activity restrictions in many communities.

The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy which directly impacts our industry and the Company.

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.

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 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 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 a gradual recovery in crude oil prices from the low point in March 2020.

However, with the uncertainty in the global market resulting from the COVID-19 pandemic, the risk 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.

As of March 3, 2021, the WTI price for a barrel of crude oil was approximately $62.

In light of the COVID-19 pandemic and the energy industry disruptions, the Permian Basin rig count decreased significantly from approximately 403 at the beginning of January 2020 to approximately 175 at the end of December 2020, according to Baker Hughes.

However, the rig count slowly increased exiting 2020 from its August low of 117 rigs.

If the rig count and market conditions do not continue to improve or worsen, the Company expects a material adverse impact on its business, results of operations and cash flows, resulting from a decrease in customer activity and pricing pressure from its customers.

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the E&P and oilfield service companies.

The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves.

The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control.

The global public health crisis associated with the COVID-19 pandemic could continue to have an adverse effect on global economic activity for the foreseeable future.

Some of the challenges resulting from the COVID-19 pandemic that have impacted our business include restrictions on movement of personnel and associated gatherings, shortage of skilled labor, cost inflation and supply chain disruptions.

Additionally, with most of the large, capitalized E&P companies in the United States, including our customers, closely managing their operating budget and exercising capital discipline, we do not currently expect significant increases in crude oil production over the short-to-medium term.

Furthermore, OPEC+ has indicated that they will continue with their plans to manage production levels by gradually increasing crude oil output.

With the tightness in crude oil production and growing demand for crude oil, there has been a significant increase in rig count and WTI crude oil prices have increased to ov er $90 per barrel in February 2022 from its recent lowest point of $20 per barrel in March 2020.

The Permian Basin rig count has increased significantly from approximately 179 at the beginning of 2021 to approximately 294 at the end of 2021, according to Baker Hughes.

Although crude oil prices are currently

at a 7-year high, the oilfield services industry, including the pressure pumping segment, has not fully recovered as evidenced by continued depressed pricing for most of our services, and shortages of skilled labor force in the Permian Basin, coupled with rising inflationary costs.

However, we still believe that the Permian Basin, our primary area of operation, will be the most attractive basin to E&P companies and should command higher prices and associated profitability, if the overall demand for crude oil and our services continues to increase.

Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the upstream and oilfield services companies.

As a result, we are working with our customers and equipment manufacturers to transition to a lower emissions profile.

The transition to lower emissions equipment is capital intensive and could require us to convert our conventional Tier II equipment to lower emissions equipment.

If we are unable to quickly transition to lower emissions equipment, the demand for our services could be adversely impacted.

Although the oil and gas industry is currently depressed, we still believe the Permian Basin, our primary area of operation, is the leading basin with the lowest break-even production cost in the United States.

If the oil and gas industry recovers, we believe there will be increased demand for pressure pumping services in the Permian Basin.

If market conditions remain depressed for a longer period of time, our profitability and future cash flows will be negatively impacted, and as a result, we may be required to record additional asset impairment charges in future periods.

Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to holiday seasons, inclement winter weather and exhaustion of our customers' annual budgets.

As a result, we typically experience declines in our operating results in November and December, even in a stable commodity price and operations environment.

Currently, a number of lower emission solutions for pumping equipment, including Tier IV DGB, electric, direct drive gas turbine and other technologies have been developed, and we expect additional lower emission solutions will be developed in the future.

We are continually evaluating these technologies and other investment and acquisition opportunities that would support our existing and new customer relationships.

The transition to lower emissions equipment is quickly evolving and will be capital intensive.

Over time, we may be required to convert substantially all of our conventional Tier II equipment to lower emissions equipment.

If we are unable to quickly transition to lower emissions equipment and meet our and our customers’ emissions goals, the demand for our services could be adversely impacted.

The Permian Basin rig count increase, WTI crude oil price increase and cost inflation could be indicative of an energy market recovery.

I f the rig count and market conditions continue to improve, including improved customers' pricing and labor availability, and we are able to meet our customers' lower emissions equipment demands, we believe our operational and financial results will also continue to improve.

However, if market conditions do not improve, and we are unable to increase our pricing or pass-through future cost increases to our customers, there could be a material adverse impact on our business, results of operations and cash flows.

Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to the holiday season, inclement winter weather and exhaustion of our customers' annual budgets.

As a result, we typically experience declines in our operating and financial results in November and December, even in a stable commodity price and operations environment.

2021 Operational Highlights

Over the course of the year ended December 31, 2021:

• we experienced a significant decline in pressure pumping equipment utilization and demand for our services, resulting from the combined effect of COVID-19 and the energy industry disruptions, which negatively impacted our operations;

• our average effectively utilized fleet count was approximately 10 active fleets, a 58% decrease from approximately 24 active fleets in 2019;

• although we gradually captured improved pricing during the year, the recent energy industry disruption and impact of COVID-19 pandemic continued to adversely impact overall demand for and pricing of our services;

• we experienced rapidly increasing inflationary cost resulting from labor and supply chain tightness, which negatively impacted our profitability and cash flows;

• our average effectively utilized fleet count was approximately 12 active fleets, a 20% increase from approximately 10 active fleets in 2020;

• we transitioned 90,000 HHP of our equipment portfolio to lower emissions, Tier IV DGB equipment.

In 2022, we plan to convert an additional 125,000 HHP to Tier IV DGB equipment, with total conversion costs expected to approximate $74 million;

• we continued to test and develop, alongside the equipment manufacturer, our existing DuraStim® equipment.

• we improved our existing processes and internal controls in 2020.

2021 Financial Highlights

Financial highlights for the year ended December 31, 2021:

• revenue decreased $1,263.1 million, or 61.5%, to $789.2 million, as compared to $2,052.3 million for the year ended December 31, 2019, primarily a result of the decrease in demand for pressure pumping services following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity;

• cost of services (exclusive of depreciation and amortization) decreased $886.1 million or 60.3% to $584.3 million, as compared to $1,470.4 million for the year ended December 31, 2019, primarily a result of our

lower utilization and activity levels, following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity;

• revenue increased $85.3 million, or 10.8%, to $874.5 million, as compared to $789.2 million for the year ended December 31, 2020, primarily a result of the increase in demand for pressure pumping services following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity;

• cost of services (exclusive of depreciation and amortization) increased $78.0 million or 13.3% to $662.3 million, as compared to $584.3 million for the year ended December 31, 2020, primarily a result of our higher utilization and activity levels, following the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity in 2020;

cost of services as a percentage of revenue increased to 75.7% in 2021 compared to 74.0% for the year ended December 31, 2020;

• general and administrative expenses, inclusive of stock-based compensation, decreased $3.8 million, or 4.4% to $82.9 million, as compared to $86.8 million for the year ended December 31, 2020;

• the total impairment expense recorded during the year December 31, 2020 was approximately $38.0 million compared to $3.4 million during the year ended December 31, 2019;

• net loss was $107.0 million, compared to a net income of $163.0 million for the year ended December 31, 2019.

Diluted net loss per common share was $1.06, compared to diluted net income per common share of $1.57 for the year ended December 31, 2019.

• no impairment expense recorded during the year December 31, 2021, compared to $38.0 million during the year ended December 31, 2020;

• net loss was $54.2 million, compared to a net loss of $107.0 million for the year ended December 31, 2020.

Diluted net loss per common share was $0.53, compared to diluted net loss per common share of $1.06 for the year ended December 31, 2020.

Adjusted EBITDA was approximately $135.0 million, compared to $141.5 million for the year ended December 31, 2020 (see reconciliation of Adjusted EBITDA to net income in the subsequent section "How We Evaluate Our Operations");

• maintained a conservative balance sheet, with cash of $69 million and no debt as of December 31, 2020 .

Actions to Address the Economic Impact of COVID-19 and Decline in Commodity Prices

• generated cash of approximately $36.0 million from the sale of our two turbines in December 2021;

• our total liquidity was $169.3 million, consisting of cash of $111.9 million and remaining availability of $57.4 million under our ABL Credit Facility;

• no debt as of December 31, 2021 under our ABL Credit Facility .

Actions to Address the Economic Impact of COVID-19

Since March 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position, liquidity and the efficient continuity of our operations as follows:

◦ Growth Capital:

we cancelled substantially all our planned growth capital expenditures for the second half of 2020.

Our 2021 capital expenditures will be driven by customer activity levels and demand for our pressure pumping services;

our operations were driven by more dedicated work from our customers.

Our capital expenditure program was focused on maintaining existing dedicated demand for our equipment.

We reduced capital investment in speculative growth.

◦ Other Expenditures :

we significantly reduced our maintenance expenditures and field level consumable costs due to our reduced activity levels in 2020.

In 2021, we will continue to seek lower pricing and cost saving measures for our expendable items, materials used in day-to-day operations and large component replacement parts;

◦ Labor Force Reductions:

we reduced our workforce by over 60% between April and May 2020 due to the changing activity levels for our services;

in 2021, we will continue to make appropriate adjustments to our workforce to reflect outlook related to our customers’ activity levels;

we strategically managed our maintenance program in line with our projected activity leve ls.

We continued to seek lower pricing and cost saving measures for our expendable items, materials used in day-to-day operations and large component replacement parts.

In addition, with the supply chain disruptions, we worked closely with our vendors to better plan our future needs and accelerated purchases of certain components and spare parts;

◦ Labor Force:

we implemented several strategies including pay adjustments of approximately 8% to retain and attract skilled workforce that will support our operations;

◦ Working Capital:

we have negotiated more favorable payment terms with certain of our larger vendors and are continuing to increase our diligence in collecting and managing our portfolio of accounts receivables.

We are continuing to evaluate and consider additional cost saving measures.

We will continue to prioritize the safety and welfare of our employees and customers through these turbulent times caused in part by COVID-19 and the depressed energy market.

we have negotiated more favorable payment terms with certain of our larger vendors, strategically disposed of certain assets to improve our liquidity position and continue to actively manage our portfolio of accounts receivables;

◦ Customer Pricing:

we continue to have ongoing pricing conversations with our customers to permit us to earn an appropriate return on our equipment and capital investments and to cover rising inflationary cost resulting from the impact of COVID-19 on labor force, supply chain and our operations in general.

Our Assets and Operations

Through our pressure pumping segment, which includes cementing operations, we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin.

Our modern hydraulic fracturing fleets have been designed to handle Permian Basin specific 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.

Our hydraulic fracturing fleets have been designed to handle Permian Basin specific 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.

We plan to continually reinvest in our equipment to ensure optimal performance and reliability.

In addition to our core pressure pumping segment 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 in the future.

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 in the future.

How We Generate Revenue

3 unchanged sentences

We charge our customers on a per‑job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job.

We also could generate revenue from idle fees from Pioneer in certain circumstances when committed fleets are idled.

We also could generate revenue from idle fees from our customers in certain circumstances when committed fleets are idled.

In addition to hydraulic fracturing services, we generate revenue through the complementary services that we provide to our customers, including cementing, coiled tubing and other related services.

5 unchanged sentences

Prices are affected by many factors beyond our control.

WTI oil prices declined significantly in 2015 and 2016 to approximately $30 per barrel, but subsequently recovered in 2017.

However, in 2020, oil and natural gas prices were highly volatile.

The average WTI oil prices per barrel were approximately $68, $39 and $57 for the years ended December 31, 2021, 2020 and 2019, respectively.

In March 2020, WTI oil prices declined significantly, to a low of approximately $20 per barrel towards the end of March 2020.

On March 3, 2021, the W TI oil price was approximat ely $62 per bar rel.

If WTI oil prices decline or continue to be depressed and do not improve or stabilize, demand for our services may be negatively impacted, which could result in a significant decrease in our profitability and cash flows.

In February 2022, the W TI oil price was over $90 per barrel.

If the WTI oil price declines in the future or remains highly volatile, demand for our services may be negat ively impacted, which could result in a significant decrease in our future profitability and cash flows.

We monitor the oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.

The historical weekly average Permian Basin rig count based on the Baker Hughes Company rig count information were as follows:

The historical weekly average Permian Basin rig count based on the Baker Hughes Company rig count information was as follows:

Year Ended December 31,

Drilling Type (Permian Basin) 2020 2019 2018

Drilling Rig Type (Permian Basin) 2021 2020 2019

Directional 2 1 5

6 unchanged sentences

Direct Labor Costs.

Payroll and benefit expenses related to our crews and other employees that are directly attributable to the effective delivery of services are included in our operating costs.

Payroll and benefit expenses related to our crews and other employees that are directly or indirectly attributable to the effective delivery of services are included in our operating costs.

Direct lab or costs amounted to 22.4% and 22.7% of total costs of service for the years ended December 31, 2021 and 2020, respectively.

The percentage increase was primarily attributable to the decrease in our revenue, resulting from customer pricing

pressure and also the increase in the number of our customers directly sourcing certain expendables like sand, diesel and chemical, as discussed below, which had the effect of reducing our revenues.

Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our pressure pumping and other operations.

1 unchanged sentence

Expendable pro duct costs comprised approximately 41.8%, and 37.6% of total costs of service for the years ended December 31, 2021 and 2020, respectively.

The percentage decrease in our expendable product cost in 2020 is primarily attributable to the increase in the number of customers sourcing these expendables directly from the vendors, and overall depressed sand prices, which has the effect of reducing our revenues.

The percentage increase in our expendable product cost in 2021 was primarily attributable to the increase in our activity levels and higher freight cost.

Other Direct Costs.

4 unchanged sentences

Other direct costs were 35.8 % and 39.7% of total costs of service for the years ended December 31, 2021 and 2020, respectively.

The percentage decrease in 2021 was primarily driven by most of our customers directly sourcing diesel and pricing improvement.

How We Evaluate Our Operations

Our management uses a variety of financial metrics, Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.

Our management uses Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.

Adjusted EBITDA and Adjusted EBITDA Margin

1 unchanged sentence

We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization.

We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, and (iii) other unusual or nonrecurring (income)/expenses, such as impairment charges, severance, costs related to asset acquisitions, costs related to SEC investigation and class action lawsuits and one-time professional and advisory fees.

We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, and (iii) other unusual or nonrecurring (income)/expenses, such as impairment charges, severance, costs related to asset acquisitions, insurance recoveries, costs related to SEC investigation and class action lawsuits and one-time professional and advisory fees.

Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.

9 unchanged sentences

Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Reconciliation of net income (loss) to Adjusted EBITDA ($ in thousands):

Reconciliation of net (loss) income to Adjusted EBITDA ($ in thousands):

Year ended December 31, 2021

Net income (loss)

$ (68,271) $ (38,749) $ (107,020)

Net loss $ (12,723) $ (41,462) $ (54,185)

Depreciation and amortization

1 unchanged sentence

Interest expense

1 2,382 2,383

Income tax benefit — (14,252) (14,252)

Loss on disposal of assets

56,659 1,477 58,136

Impairment expense 36,907 1,095 38,002

Loss (gain) on disposal of assets 64,903 (257) 64,646

Stock‑based compensation

— 11,519 11,519

Other expense

Other income — (873) (873)

Other general and administrative expense (1)

— (6,471) (6,471)

Retention bonus and severance expense 75 1,065 1,140

Severance expense 30 602 632

Adjusted EBITDA

2 unchanged sentences

Year ended December 31, 2020

Net income (loss)

$ 281,090 $ (118,080) $ 163,010

Net loss $ (68,271) $ (38,749) $ (107,020)

Depreciation and amortization

2 unchanged sentences

1 2,382 2,383

Income tax expense

— 50,494 50,494

Income tax benefit — (27,480) (27,480)

Loss on disposal of assets

6 unchanged sentences

— 13,038 13,038

Deferred IPO bonus, retention bonus and severance expense 7,093 2,110 9,203

Retention bonus and severance expense 75 1,065 1,140

Adjusted EBITDA

9 unchanged sentences

Income tax expense — 50,494 50,494

— 51,255 51,255

Loss on disposal of assets

106,178 633 106,811

Impairment expense — 3,405 3,405

Stock‑based compensation

2 unchanged sentences

Other general and administrative expense (1)

Deferred IPO bonus

— 25,208 25,208

Deferred IPO bonus, retention bonus and severance expense 7,093 2,110 9,203

Adjusted EBITDA

1 unchanged sentence

____________________

(1) During the years ended December 31, 2020 and 2019, other general and administrative expense primarily relates to nonrecurring professional fees paid to external consultants in connection with the Company’s expanded audit committee review, SEC investigation and shareholder litigation.

All nonrecurring professional fees incurred after the end of June 2020 are in connection with the pending SEC investigation and shareholder litigation.

The other general and administrative expense during the year ended December 31, 2018 primarily relates to legal settlements.

(1) During the years ended December 31, 2021, 2020 and 2019, other general and administrative expense (net of reimbursement from insurance carriers) primarily relates to nonrecurring professional fees paid to external consultants in connection with our audit committee review, SEC investigation and shareholder litigation, net of insurance recoveries.

During the years ended December 31, 2021, 2020 and 2019, we received reimbursement of approximately $9.8 million , $0.6 million and $0, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.

Results of Operations

1 unchanged sentence

hydraulic fracturing, cementing and coiled tubing.

In March 2020, the Company shut down its flowback operating segment and subsequently disposed of the assets for approximately $1.6 million.

In September 2020, the Company disposed of all of its drilling rigs and ancillary assets for approximately $0.5 million and shut down its drilling operations.

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

The comparability of the results of operations for the years ended December 31, 2020 and 2019 have been impacted by the decrease in demand for pressure pumping services following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity during the year ended December 31, 2020.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

11 unchanged sentences

Interest expense 614 2,383 (1,769) (74.2) %

Other expense 874 717 157 21.9 %

Income tax expense (27,480) 50,494 (77,974) (154.4) %

Net (loss) income $ (107,020) $ 163,010 $ (270,030) (165.7) %

Other expense (income) (873) 874 1,747 199.9 %

Income tax benefit (14,252) (27,480) (13,228) (48.1) %

Net loss $ (54,185) $ (107,020) $ (52,835) (49.4) %

Adjusted EBITDA (3)

10 unchanged sentences

(1) Exclusive of depreciation and amortization.

(2) Inclusive of stock‑based compensation of $9.1 million and $7.8 million for 2020 and 2019, respectively.

(3) For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read “How We Evaluate Our Operations.” Included in our Adjusted EBITDA is idle fees of $47.2 million and $13.3 million for the years ended December 31, 2020 and 2019, respectively.

(2) Inclusive of stock‑based compensation o f $11.5 million and $9.1 million for 2021 and 2020, respectively.

" Included in our Adjusted EBITDA is idle fees of $9.5 million and $47.2 million for the years ended December 31, 2021 and 2020, respectively.

(4) The non‑GAAP financial measure of Adjusted EBITDA margin for the pressure pumping segment is calculated by taking Adjusted EBITDA for the pressure pumping segment as a percentage of our revenues for the pressure pumping segment.

Revenue decreased 61.5%, or $1,263.1 million, to $789.2 million for the year ended December 31, 2020, as compared to $2,052.3 million for the year ended December 31, 2019.

Our pressure pumping segment revenues decreased 61.4%, or $1,228.2 million for the year ended December 31, 2020, as compared to the year ended December 31, 2019.

The decreases were primarily attributable to the significant decrease in demand for pressure pumping services, as well as pricing discounts we provided to our customers following the depressed oil prices and slowdown in economic activity resulting from the COVID-19 pandemic.

The decrease in demand for our pressure pumping services resulted in a significant decrease in our average effectively utilized fleet count to approximately 10.2 active fleets in 2020 from 23.9 active fleets in 2019.

Furthermore, the decrease in our revenue was also driven by the increase in our customers directly sourcing from vendors certain consumables like sand, chemicals and fuel.

Included in our revenue for the years ended December 31, 2020 and 2019 was revenue generated from idle fees charged to our customer of approximately $47.2 million and $13.3 million, respectively.

Revenues from services other than pressure pumping decreased 68.9%, or approximately $34.9 million, for the year ended December 31, 2020, as compared to the year ended December 31, 2019.

The decrease in revenues from services other than pressure pumping during the year ended December 31, 2020, was primarily attributable to the shutdown of our flowback operations and also a significant reduction in utilization experienced in our coiled tubing operations, which was driven by lower E&P completions activity following the depressed oil prices and impact of the COVID-19 pandemic.

Revenue increased 10.8%, or $85.3 million, to $874.5 million for the year ended December 31, 2021, as compared to $789.2 million for the year ended December 31, 2020.

Our pressure pumping segment revenues increased 10.9%, or $84.2 million for the year ended December 31, 2021, as compared to the year ended December 31, 2020.

The increases were primarily attributable to the significant increase in demand for pressure pumping services, following the rebound from the depressed oil prices and slowdown in economic activity resulting from the COVID-19 pandemic.

The increase in demand for our pressure pumping services resulted in an approximate 20% increase in our average effectively utilized fleet count to approximately 12 active fleets in 2021 from 10 active fleets in 2020.

Included in our revenue for the years ended December 31, 2021 and 2020 was revenue generated from idle fees charged to a certain customer of approximately $9.5 million and $47.2 million, respectively.

Revenues from services other than pressure pumping increased 7.1%, or approximately $1.1 million , for the year ended December 31, 2021, as compared to the year ended December 31, 2020.

The increase in revenues from services other than pressure pumping during the year ended December 31, 2021, was primarily attributable to the increase in utilization experienced in our coiled tubing operations, which was driven by increased E&P completions activity following the rebound from the depressed oil prices and impact of the COVID-19 pandemic.

Cost of Services.

Cost of services decreased 60.3%, or $886.1 million, to $584.3 million for the year ended December 31, 2020, from $1,470.4 million during the year ended December 31, 2019.

Cost of services in our pressure pumping segment decreased $858.2 million during the year ended December 31, 2020, as compared to the year ended December 31, 2019.

The decreases were primarily attributable to our lower utilization and activity levels, following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity.

As a percentage of pressure pumping segment revenues (including idle fees), pressure pumping cost of services increased to 73.8% for the year ended December 31, 2020, as compared to 71.4% for the year ended December 31, 2019.

Excluding idle fees revenue of $47.2 million and $13.3 million for the years ended December 31, 2020 and 2019, respectively, our pressure pumping cost of services as a percentage of pressure pumping revenues for the years ended December 31, 2020 and 2019 was approximately 78.5% and 71.9%, respectively.

The increase in our cost of services percentage was primarily attributable to pricing pressure on our services resulting from customer discounts.

Our pricing in 2020 was significantly depressed following the economic slowdown caused by COVID-19 pandemic and depressed oil prices.

Cost of services increased 13.3%, or $78.0 million, to $662.3 million for the year ended December 31, 2021, from $584.3 million during the year ended December 31, 2020.

Cost of services in our pressure pumping segment increased $77.1 million during the year ended December 31, 2021, as compared to the year ended December 31, 2020 .

The increases were primarily attributable to our higher utilization and activity levels, following the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity in 2020.

A s a percentage of pressure pumping segment revenues (including idle fees), pressure pumping cost of services increased to 75.5% for the year ended December 31, 2021, as compared to 73.8% for the year ended December 31, 2020.

Excluding idle fees revenue of $9.5 million and $47.2 million for the years ended December 31, 2021 and 2020, respectively, our pressure pumping cost of services as a percentage of pressure pumpin g revenues for the years ended December 31, 2021 and 2020 was approximately 76.4% and 78.5%, respectively.

The decrease was a result of increased customer activity levels, which is consistent with our increased fleet utilization, coupled with significant pricing pressure in 2020.

General and Administrative Expenses.

General and administrative expenses decreased 4.4%, or $3.8 million, to $82.9 million for the year ended December 31, 2021, as compared to $86.8 million for the year ended December 31, 2020.

The net decrease was primarily attributable to a decrease during 2020 in (i) nonrecurring professional fees of $12.2 million, which was primarily attributable to the Company's expanded audit committee internal review, pending SEC investigation and shareholder litigation, (ii) retention and other bonuses, and severance expense of $8.1 million;

(iii) property taxes of $1.6 million, and (iv) $5.0 million in other remaining general and administrative expenses, which was partially offset by a net increase of approximately $7.2 million paid in legal, accounting and consulting professional fees, and stock based compensation expense of $1.3 million.

The net decrease was primarily attributable to the decrease in (i) nonrecurring advisory and professional fees of $19.4 million, which was primarily attributable to the Company's expanded audit committee internal review, SEC investigation and shareholder litigation, (ii) legal and professional fees of $3.9 million, which was partially offset by net increases of (iii) $15.8 million in payroll expenses, (iv) $2.4 million of stock based compensation expense, (v) $1.2 million in insurance expense and (vi) $0.1 million in other remaining general and administrative expenses.

Depreciation and Amortization.

Depreciation and amortization increased 5.5%, or $8.0 million, to $153.3 million for the year ended December 31, 2020, as compared to $145.3 million for the year ended December 31, 2019.

The increase was primarily attributable to the overall increase in our fixed asset base as of December 31, 2020.

Depreciation and amortization decreased 13.0%, or $19.9 million, to $133.4 million for the yea r ended December 31, 2021, as compared to $153.3 million for the year ended December 31, 2020.

The decrease was primarily attributable to the overall decrease in our fixed asset base as of December 31, 2021, partly attributable to the impairment of certain fixed assets in 2020.

Impairment Expense.

During the year ended December 31, 2020, the depressed market conditions, crude oil prices and negative near-term outlook for the utilization of certain of our equipment, resulted in the Company recording an impairment expense of approximately $38.0 million, of which $9.4 million relates to goodwill impairment and $28.6 million relates to property and equipment impairment.

The substantial portion of our impairment expense relates to our pressure pumping segment.

During the year ended December 31, 2019, we recorded $3.4 million property and equipment impairment expense in connection with our drilling rigs and flowback assets.

There was no impairment expense during the year ended December 31, 2021.

During the year ended December 31, 2020, the depressed market conditions, crude oil prices and negative near-term outlook for the utilization of certain of our equipment, resulted in the Company recording an impairment expense of approximately $38.0 million, of which $9.4 million related to goodwill impairment and $28.6 million related to property and equipment impairment.

The substantial portion of our impairment expense in 2020 related to our pressure pumping segment.

Loss on Disposal of Assets.

Loss on the disposal of assets decreased 45.6%, or $48.7 million, to $58.1 million for the year ended December 31, 2020, as compared to $106.8 million for the year ended December 31, 2019.

The decrease was primarily attributable to a decrease in utilization resulting from a reduction in the operational intensity of our equipment during 2020.

Upon sale or retirement of property and equipment, including certain major components like fluid ends and power ends of our pressure pumping equipment that are replaced, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets.

Loss on the disposal of assets increased 11.2%, or $6.5 million, to $64.6 million for the year ended December 31, 2021, as compared to $58.1 million for the year ended December 31, 2020.

The increase was primarily attributable to an increase in utilization resulting from an increase in the operational intensity of our equipment during 2021.

Upon sale or retirement of property and equipment, including certain major

components like fluid ends and power ends of our pressure pumping equipment that are replaced, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets.

Interest Expense.

Interest expense decreased 66.6%, or $4.8 million, to $2.4 million for the year ended December 31, 2020, as compared to $7.1 million for the year ended December 31, 2019.

The decrease in interest expense was primarily attributable to a decrease in our average debt balance in 2020 compared to 2019.

Other Expense.

Other expense was relatively flat at $0.9 million for the year ended December 31, 2020, similar to $0.7 million for the year ended December 31, 2019.

Our other expense primarily comprised of our lenders administration fees.

Income Tax Expense.

Income tax benefit was $27.5 million for the year ended December 31, 2020, as compared to income tax expense of $50.5 million for the year ended December 31, 2019.

The income tax benefit recorded during the year ended December 31, 2020 is primarily attributable to the Company ending in a pre-tax loss position in 2020 as compared to a pre-tax income in 2019.

Our effective tax rate was 20.4% during the year ended December 31, 2020 compared to 23.7% during the year ended December 31, 2019.

Interest expense decreased 74.2%, or $1.8 million, to $0.6 million for the year ended December 31, 2021, as compared to $2.4 million for t he year ended December 31, 2020.

The decrease in interest expense was primarily attributable to a decrease in our financing arrangements and zero debt in 2021, compared to 2020.

Our interest expense consist primarily of amortization of our original loan cost.

In 2021, we have zero debt under our ABL Credit Facility.

Other Expense (Income).

Other income increased to approximately $0.9 million for the year ended December 31, 2021, as compared to $0.9 million in expense for the year ended December 31, 2020.

The increase in other income is primarily attributable to the net refund of approximately $2.1 million to the Company from a sales and excise and use tax audit and partially offset by an expense related to our lender's commitment fees during the year ended December 31, 2021, as compared to the year ended December 31, 2020.

Income Tax Benefit.

Income tax benefit was $14.3 million for the year ended December 31, 2021, as compared to income tax benefit of $27.5 million for the year ended December 31, 2020.

The reduction in income tax benefit recorded during the year ended December 31, 2021 is primarily attributable to the Company projecting a much lower pre-tax loss in 2021 as compared to that in 2020.

Furthermore, there was no significant change in the effective tax rate from 20.8% during the year ended December 31, 2021, compared to 20.4% during the year ended December 31, 2020.

Liquidity and Capital Resources

Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our revolving credit facility ( " ABL Credit Facility " ).

Our primary uses of cash will be to continue to fund our operations, support growth opportunities and satisfy debt payments, if any.

Our borrowing base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable.

Our borrowing base as of December 31, 2020 was approximately $55.6 million and was approxi mately $48.9 million as of March 3, 2021.

Our cash is primarily used to fund our operations, support growth opportunities and satisfy debt payments, if any.

Our borrowing base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable (the "borrowing base").

Our borrowing base as of December 31, 2021 was approximately $61.1 million and was approxi mately $79.0 million a s of February 18, 2022.

Changes to our operational activity levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility.

We believe our remaining monthly availability under our ABL Credit Facility will be adversely impacted if the current depressed oil and gas market conditions continue or worsen.

We believe our remaining monthly availability under our ABL Credit Facility will be adversely impacted if oil and gas market conditions decline in the future.

As of December 31, 2021, we had no borrowings under our ABL Credit Facility and our total liquidity was $169.3 million, consisting of cash and cash equivalents of $111.9 million and $57.4 million of availability under our ABL Credit Facility.

As of March 5, 2021, we had no borrowings under our ABL Credit Facility and our total liquidity was approximately $89.6 million, consisting of cash and cash equivalents of $44.4 million and $45.2 million of availability under our ABL Credit Facility.

During the second quarter of 2020 and through July 2020 , when demand for our services was significantly depressed following the rapidly rising health crisis associated with the COVID-19 pandemic and the energy industry disruptions led by depressed WTI crude oil prices, the Company experienced a decrease in its liquidity.

If there is a reduction in the COVID-19 infection rate and the ongoing distribution and administration of COVID-19 vaccines lead to a gradual recovery in crude oil prices, we would expect demand for crude oil and consequently the demand for our pressure pumping services to improve during 2021.

Combined with our cost reduction initiatives, we have slowly increased our liquidity position over the second half of 2020 and into 2021 and expect our liquidity to continue to gradually increase in 2021, if market conditions continue to improve.

The current market conditions resulting from the COVID-19 pandemic are rapidly changing and there could be a new outbreak of a COVID-19 variant.

Our future revenue, results of operations and cash flows could be negatively impacted if the COVID-19 pandemic is not contained or if the vaccines currently distributed and administered to people are not as effective as anticipated, and if current market conditions do not improve.

As of February 18, 2022, we had no borrowings under our ABL Credit Facility and our total liquidity was approximately $151.3 million, consisting of cash and cash equivalents of $76.0 million and $75.3 million of availability under our ABL Credit Facility.

In 2020 when demand for our services was significantly depressed following the rapidly rising health crisis associated with the COVID-19 pandemic and the energy industry disruptions, the Company experienced a significant decrease in its liquidity.

However, with the gradual recovery in the energy industry and increase in demand for our services in 2021, our liquidity position has gradually improved and this improvement has continued into the beginning of 2022, as market conditions have continued to improve, although we expect our overall liquidity to decline during 2022 as we make additional capital investments.

Moreover, the current market conditions resulting from the COVID-19 pandemic have and may in the future change rapidly and there could be a new outbreak of a COVID-19 variant that could result in travel restrictions, business closure and institution of quarantining and/or other activity restrictions, which could negatively impact our future operations, revenue, profitability and cash flows if not contained or if the vaccines currently distributed and administered to people are not as effective as anticipated in curbing the spread of any such new COVID-19 variant.

There can be no assurance that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.

9 unchanged sentences

$ (104,292) $ (94,217)

Net cash (used in) provided by financing activities

Net cash used in financing activities

$ (7,276) $ (125,171)

1 unchanged sentence

Net cash provided by operating activities was $154.7 million for the year ended December 31, 2021, as compared to $139.1 million for the year ended December 31, 2020.

The net decrease of $316.2 million was primarily due to the reduction in our activity levels in 2020, resulting from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted our o perations.

The net decrease in cash

provided by operating activities was also impacted by the timing of our receivable collections from our customers and payment to our vendors.

The net increase of $15.6 million was primarily due to the reduction in our net loss, resulting from an increase in our activity levels in 2021, and the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted our

o perations in 2020.

The net increase in cash provided by operating activities was also slightly impacted by the timing of our receivable collections from our customers and payment to our vendors.

Investing Activities

Net cash used in investing activities decreased to $94.2 million for the year ended December 31, 2020, from $495.3 million for the year ended December 31, 2019.

The net decrease in our cash used in investing activities was primarily attributable to the reduction in growth and maintenance capital expenditures in 2020 following the lower number of pressure pumping active fleets, equipment rotation (resulting in lower intensity on our pressure pumping equipment) and the depressed demand for our pressure pumping services.

During the year ended December 31, 2019, the Company made a cash payment of approximately $110.0 million in connection with the Pioneer Pressure Pumping Acquisition and paid approximately $145.3 million for 108,000 HHP of DuraStim® hydraulic fracturing equipment and turbines (including an option payment of $6.1 million to purchase an additional 108,000 HHP of DuraStim® equipment).

Net cash used in investing activities increased to $104.3 million for the year ended December 31, 2021, from $94.2 million for the year ended December 31, 2020.

The net increase in our cash used in investing activities was primarily attributable to our investment in Tier IV DGB equipment.

Included in our net cash used for investing activities in 2021 was a cash payment of $45.3 million for new Tier IV DGB equipment.

The remaining cash payments in 2021 were incurred in connection with our maintenance capital expenditures and other growth initiatives.

Ou r cash flow from investing activities was partially offset by $36.0 million of cash generated from the sale of our two turbine generators in December 2021.

Financing Activities

Net cash used in financing activities was $125.2 million for the year ended December 31, 2020, compared to net cash provided of $56.3 million for the year ended December 31, 2019.

The net decrease in cash flow from financing activities during the year ended December 31, 2020 was primarily driven by the repayment of our outstanding borrowings under ABL Credit Facility of $130.0 million, compared to net borrowings of $60.0 million during the year ended December 31, 2019.

During the year ended December 31, 2020, we received cash flow from our insurance financing arrangement of $6.8 million and made repayments of $1.3 million related to our insurance financing.

Net cash used in financing activities was $7.3 million for the year ended December 31, 2021, compared to net cash used of $125.2 million for the year ended December 31, 2020.

The net decrease in cash flow from financing activities during the year ended December 31, 2021 was primarily driven by no borrowings or repayments under our ABL Credit Facility in 2021 compared to repayment of borrowings of $130.0 million during the year ended December 31, 2020.

During the year ended December 31, 2021, net cash outflow in connection with insurance financing was approximately $5.5 million, whereas during the year ended December 31, 2020 we received net cash inflow of $5.5 million.

Credit Facility and Other Financing Arrangements

1 unchanged sentence

Our ABL Credit Facility, as amended, has a total borrowing capacity of $300 million (subject to the borrowing base limit), with a maturity date of December 19, 2023.

The ABL Credit Facility has a borrowing base of 85% of monthly eligible accounts receivable less customary reserves (the "Borrowing Base").

The ABL Credit Facility has a borrowing base of 85% of monthly eligible accounts receivable less customary reserves.

The borrowing base as of December 31, 2021 was approximately $61.1 million .

3 unchanged sentences

Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero.

The weighted average interest rate under our ABL Credit Facility for the year e nded December 31, 2020 was 3.6%.

In March 2020, we obtained a waiver from our lenders under the ABL Credit Facility to extend the time period for us to provide our lenders the Company’s audited financial statements for the year ended December 31, 2019 to July 31, 2020, which we have provided to our lenders.

As of December 31, 2021, we had no borrowings outstanding under our ABL Credit Facility.

During the year ended December 31, 2020, we repaid all borrowings under our ABL Credit Facility of approximately $130.0 million with cash flows from operations and our available cash.

Our objective is to maintain a conservative leverage ratio throughout 2021.

Off Balance Sheet Arrangements

3 unchanged sentences

During the year ended December 31, 2020, we reduced our capital expenditures following the depressed demand for our pressure pumping services as a result of the COVID-19 pandemic and depressed energy market.

During the year ended December 31, 2020, the significant portion of our total capital expenditures were comprised of maintenance capital expenditures.

The significant portion of our total capital expenditures were comprised of maintenance capital expenditures.

Our future material use of cash will be to fund our capital expenditures.

Capital expenditures for 2021 are projected to be primarily related to maintenance capital expenditures to support our existing assets (including costs to convert existing equipment to lower emissions pressure pumping equipment), depending on market conditions and customer demand.

Our future capital expenditures depend on our projected operational activity, emission requirements and new technology, among other factors, which could vary throughout the year.

Based on our current projected activity levels for 2021, we expect our capital expenditures to range between $115.0 million to $130.0 million (which includes approximately $37.0 million to acquire new Tier IV DGB dual fuel equipment and convert some of our conventional Tier II equipment to lower emissions Tier IV DGB equipment), which is highly dependent on several factors including market conditions.

The Company will continue to evaluate the emissions profile of its fleet over the coming years and may convert or retire conventional Tier II equipment in favor of lower emissions equipment.

The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors) the future impact of the COVID-19 pandemic, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures.

Capital expenditures for 2022 are projected to be primarily related to maintenance capital expenditures to support our existing pressure pumping assets, costs to convert some existing equipment to lower emissions pressure pumping equipment, strategic purchases and other ancillary equipment purchases, subject to market conditions and customer demand.

Our future capital expenditures depend on our projected operational activity, emission requirements and planned conversions to lower emissions equipment, among other factors, which could vary significantly throughout the year.

Based on our current plan and projected activity levels for 2022, we expect our capital expenditures to range between $250.0 million to $300.0 million.

We could incur significant additional capital expenditures if our projected activity levels increase during the course of the year, inflation and supply chain tightness continues to adversely impact on our operations or we invest in new or different lower emissions equipment.

The Company will continue to evaluate the emissions profile of its fleet over the coming years and may, depending on market conditions, convert or retire additional conventional Tier II equipment in favor of lower emissions equipment.

The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors) the availability of equipment, including parts and major components, supply chain disruptions, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures.

Depending on the impacts of these factors, the Company may decide to retain conventional equipment for a longer period of time or accelerate the retirement, replacement or conversion of that equipment.

In addition, we have option agreements with our equipment manufacturer to purchase an additional 108,000 HHP of DuraStim® hydraulic fracturing equipment thr ough July 31, 2022.

We believe the cost to acquire the DuraStim® hydraulic fracturing equipment will be comparable to our previously purchased DuraStim® hydraulic fracturing equipment.

In the current economic environment, it is not probable we w ould exercise these options before they expire.

We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility.

7 unchanged sentences

Operating leases (2)

Other purchase obligation (3)

1,250 1,250 —

Total $ 487 $ 389 $ 98

2 unchanged sentences

If we decide to borrow from our ABL Credit Facility in the future, interest expense will be charged based on the agreed contractual interest rates.

However, we are obligated to pay agency and

commitment fees on unused balance which could be up to approximately $1.2 million annually, depending on our utilization of the ABL Credit Facility.

However, we are obligated to pay agency and commitment fees on unused balance which could be up to approximately $1.2 million annually, depending on our utilization of the ABL Credit Facility.

(2) Operating leases exclude short-term leases and other commitments (see Note 14.

1 unchanged sentence

Commitments and Contingencies in the financial statements for additional disclosures).

(3) Other purchase obligation relates to vendor related commitments in connection with the supply and storage of certain consumables.

The Company enters into purchase agreements with the Sand suppliers to secure supply of sand in the normal course of its business.

The agreements with the Sand suppliers require that we purchase certain sand volumes, which is based on a certain percentage of our overall sand requirements and agreed minimum volumes, otherwise certain penalties may be charged.

Under certain of the purchase agreements, a shortfall fee applies if we purchase less than the agreed percentage of our sand requirements or agreed minimum volumes.

The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes.

Our current agreements with Sand suppliers expire at different times prior to April 30, 2022.

We enter into purchase agreements with Sand suppliers to secure supply of sand in the normal course of our business.

The agreements with the Sand suppliers require that we purchase minimum volume of sand, based primarily on a certain percentage of our sand requirements from our customers or in certain situations based on predetermined fixed minimum volumes, otherwise certain penalties (shortfall fees) may be charged.

The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the mi nimum volumes or a fixed price per ton of unpurchased volumes.

Our current agreements with Sand suppliers expire at different times prior to December 31, 2025.

Our agreed upon sand requirements or minimum volumes are based on certain future events such as our customer demand, which cannot be reasonably estimated.

If the activity level of our customers declines and the future demand for our services is materially and adversely affected, we may be required to pay for more sand from one of our Sand suppliers than we need in the performance of our services, regardless of whether we take physical delivery of such sand.

In such an event, we may be required to pay shortfall fees or other penalties under the purchase agreement, which could have a material adverse effect on our business, financial condition, or results of operations.

Recent Accounting Pronouncements

26 unchanged sentences

The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.

During the first quarter of 2020, management determined the reductions in commodity prices driven by the impact of the novel COVID-19 virus and global supply and demand dynamics coupled with the sustained decrease in the Company’s share price were triggering events for asset impairment.

Furthermore, in light of the energy industry transition to lower emissions equipment, the Company made a strategic decision in December 2020 to retire approximately 150,000 HHP of our conventional Tier II pressure pumping equipment.

As a result of these triggering events, we performed recoverability tests on each of the assets groups and recorded impairment expense during the year ended December 31, 2020 as follows:

• in the first quarter of 2020, we recorded drilling asset impairment of approximately $1.1 million as a result of the negative near-term outlook of our drilling assets utilization;

• in the first quarter of 2020, we recorded an impairment expense of $6.1 million in our pressure pumping reportable segment related to our options deposit to purchase additional DuraStim® equipment, for which the options expire at various times through the end of July 2022, as it is not probable we would exercise our options due to the events described above;

• in the fourth quarter of 2020, we recorded an impairment expense of approximately $21.3 million, in our pressure pumping reportable segment, in connection with our planned retirement of approximately 150,000 HHP of our conventional Tier II pressure pumping equipment.

If the crude oil market declines or the demand for our services does n ot recover, and if our equipment remains idle or under‑utilized, the estimated fair value of such equipment may decline, which could result in future impairment charges.

Though the impacts of variations in any of these factors can have compounding or off‑setting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment.

Our DuraStim® equipment is yet to be commercialized.

If we are not able to successfully commercialize the DuraStim® equipment, and are not able to deploy the equipment for alternative uses, we will incur impairment losses on the carrying value of the DuraStim® equipment.

As of December 31, 2021, the carrying value of our DuraStim® equipment is approximately $90 million.

Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized.

5 unchanged sentences

As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast.

In March 2020, crude oil prices declined significantly, an indication that a triggering event has occurred, and as such, we recorded in our pressure pumping reportable segment, goodwill impairment expense of $9.4 million during the year ended December 31, 2020.

There was no carrying value for goodwill in our balance sheet as of December 31, 2020 because our goodwill carrying value was fully written off during the year.

during the year ended December 31, 2020.

There was no carrying value for goodwill in our balance sheet as of December 31, 2021 because our goodwill carrying value was fully written off during 2020.

Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements.

13 unchanged sentences

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 7. Management’s Discussion and Analysis