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Item 7. Management’s Discussion and Analysis

2021-03-05 compared with 2020-06-22 · 248 added, 182 removed, 220 unchanged (66% of the section changed)

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Basis of Presentation

This discussion of our results of operations omits our results of operations for the year ended December 31, 2017 and the comparison of our results of operations for the years ended December 31, 2018 and 2017 , which may be found in our Annual Report on Form 10-K for the year ended December 31, 2018 , filed with the SEC on March 1, 2019.

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.

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 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, 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 exploration and production, or 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.

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, or units, 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.

As such, our total available HHP at December 31, 2019 was 1,469,000 HHP, which 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’ and operational needs.

Our first DuraStim® hydraulic fracturing pumps of 54,000 HHP was delivered in December 2019 and deployed to a customer in January 2020.

We expect that the additional DuraStim® hydraulic fracturing pumps of 54,000 HHP will be delivered during 2020.

We also have an option to purchase up to an additional 108,000 HHP of DuraStim® hydraulic fracturing pumps in the future through April 30, 2021.

The DuraStim® technology is powered by electricity.

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

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.

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.

Pioneer Pressure Pumping Acquisition

On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer Natural Resources USA, Inc.(“Pioneer”) and Pioneer Pumping Services, LLC (the “Pioneer Pressure Pumping Acquisition”).

On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer and Pioneer Pumping Services, LLC in the Pioneer Pressure Pumping Acquisition.

The pressure pumping assets acquired included hydraulic fracturing pumps of 510,000 HHP, four coiled tubing units and the associated equipment maintenance facility.

In connection with the acquisition, we became a long-term service provider to Pioneer under a Pressure Pumping Services Agreement (the “Pioneer Services Agreement”), providing pressure pumping and related services for a term of up to 10 years;

In connection with the acquisition, we became a long-term service provider to Pioneer under the Pioneer Services Agreement, providing pressure pumping and related services for a term of up to 10 years;

provided, that Pioneer has the right to terminate the Pioneer Services Agreement, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026.

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

At the present, we

have eight fleets committed to Pioneer.

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.

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 restrictions on movement 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.

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

Russia 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, 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 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 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 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.

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.

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.

2020 Operational Highlights

Over the course of the year ended December 31, 2019 , we:

Placed in service, at the beginning of 2019, pressure pumping and related assets (510,000 HHP) acquired in connection with the Pioneer Pressure Pumping Acquisition, which resulted in an increase to our revenue and profitability in 2019;

Purchased 108,000 HHP of DuraStim® hydraulic fracturing pumps with the first DuraStim® pumps of 54,000 HHP delivered in December 2019, while the remaining hydraulic fracturing pumps or 54,000 HHP expected to be delivered in 2020;

Entered into a purchase option agreement with our equipment supplier to purchase additional DuraStim® hydraulic fracturing pumps of 108,000 HHP;

Maintained a high fleet utilization for the year 2019;

Improved operational and financial processes by making changes to senior management in 2019.

Over the course of the year ended December 31, 2020:

• 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;

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

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

2020 Financial Highlights

F inancial highlights for the year ended December 31, 2019 :

Revenue increased $347.8 million , or 20.4% , to $2,052.3 million , as compared to $1,704.6 million for the year ended December 31, 2018 , primarily a result of the increase in our fleet size in connection with the Pioneer Pressure Pumping Acquisition placed in service at the beginning of 2019;

Cost of services (exclusive of depreciation and amortization) increased $199.8 million or 15.7% to $1,470.4 million , as compared to $1,270.6 million for the year ended December 31, 2018 , primarily a result of the increase in head count and higher activity levels resulting from the increase in fleet size.

Cost of services as a percentage of revenue decreased to 71.6% in 2019 compared to 74.5% for the year ended December 31, 2018 ;

General and administrative expenses, inclusive of stock-based compensation (“G&A”), increased $51.1 million , or 94.7% to $105.1 million , as compared to $54.0 million for the December 31, 2018 .

G&A as a percentage of revenue increased to 5.1% in 2019 from 3.2% for the year ended December 31, 2018 .

The increase was driven by increase in legal and professional fees, payroll related expense and net increase in other G&A expenses resulting partly from the expansion of our business with the Pioneer Pressure Pumping Acquisition.

Included in G&A was approximately $24.2 million related to legal and professional fees incurred in connection with the Audit Committee internal review;

Net income was $163.0 million , compared to $173.9 million for the December 31, 2018 .

Diluted net income per common share was $1.57 , compared to $2.00 for the year ended December 31, 2018 .

Adjusted EBIDTA was approximately $519.1 million , compared to $388.5 million for the year ended December 31, 2018 (see reconciliation of Adjusted EBITDA to net income in the subsequent section “How We Evaluate Our Operations”) ;

Maintained a conservative balance sheet and sufficient liquidity.

Financial highlights for the year ended December 31, 2020:

• 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;

cost of services as a percentage of revenue increased to 74.0% in 2020 compared to 71.6% for the year ended December 31, 2019;

• general and administrative expenses, inclusive of stock-based compensation, decreased $18.3 million, or 17.4% to $86.8 million, as compared to $105.1 million for the year ended December 31, 2019;

• 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.

Adjusted EBITDA was approximately $141.5 million, compared to $519.1 million for the year ended December 31, 2019 (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

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◦ Growth Capital:

We cancelled substantially all our planned growth capital expenditures for the remainder of 2020.

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;

◦ Other Expenditures:

We significantly reduced our maintenance expenditures and field level consumable costs due to our reduced activity levels.

We have been seeking lower pricing for our expendable items, materials used in day-to-day operations and large component replacement parts.

Also, we have been internalizing certain support services that were outsourced.

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 have reduced our workforce by over 60% due to the changing activity levels for our services.

We will continue to make appropriate adjustments to our workforce to reflect outlook related to activity levels.

Compensation Related Costs.

The directors and officers have voluntarily reduced compensation at different levels up to 20%.

We have taken efforts to manage work schedules, primarily related to hourly employees, to minimize overtime costs.

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;

◦ Working Capital:

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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.

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.

Our Assets and Operations

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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.

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

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

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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.

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 services.

We also could generate revenue from idle fees from Pioneer 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.

These complementary services are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services.

We are also sometimes paid by the hour for these complementary services.

Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count.

Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices.

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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 and 2018.

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 price per barrel was approximately $57, $65 and $51 for the years ended December 31, 2019 , 2018 and 2017 , respectively.

Demand for our services is largely dependent on oil and natural gas prices, and our customers’ completion budgets and rig count.

The average WTI oil prices per barrel were approximately $39, $57 and $65 for the years ended December 31, 2020, 2019 and 2018, respectively.

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

On June 17, 2020 the WTI oil price was approximately $38 per barrel.

If such depressed prices continue or do not improve, demand for our services will be negatively impacted and result in a significant decrease in our profitability and cash flows.

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.

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 Incorporated rig count information were as follows:

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

Year Ended December 31,

Drilling Type (Permian Basin) 2020 2019 2018

Directional 1 5 6

Horizontal 212 405 418

Vertical 8 32 43

Total 221 442 467

Average Permian Basin rig count to U.S rig count 51.0 % 46.9 % 45.2 %

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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.

Direct labor costs amounted to 19.6% and 13.1% of total costs of service for the years ended December 31, 2019 and 2018 , respectively.

The percentage increase in our direct labor costs was driven primarily by the increase in the crew costs and also the increase in the number of our customers directly sourcing certain expendables like sand and chemical, as discussed below, which has the effect of reducing our revenues.

Direct lab or costs amounted to 22.7% and 19.6% of total costs of service for the years ended December 31, 2020 and 2019, 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.

These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services.

Expendable product costs comprised approximately 40.8%, and 56.0% of total costs of service for the years ended December 31, 2019 and 2018 , respectively.

The percentage decrease in our expendable product cost in 2019 is primarily attributable to the increase in the number of customers sourcing these expendables directly from the vendors and an increase in the use of less expensive regional sand, and overall depressed sand prices, which has the effect of reducing our revenues.

Expendable pro duct costs comprised approximately 37.6%, and 40.8% of total costs of service for the years ended December 31, 2020 and 2019, 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.

Other Direct Costs.

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Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs.

Capital expenditures to upgrade or extend the useful life of equipment are not included in other direct costs.

Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs.

Other direct costs were 39.7% and 39.6% of total costs of service for the years ended December 31, 2020 and 2019, respectively.

The percentage increase in our other direct costs was primarily a result of the increase in the number of our customers directly sourcing certain expendables like sand and chemical, as discussed above, which has the effect of reducing our revenues.

How We Evaluate Our Operations

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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) loss/(gain) on extinguishment of debt, (iii) stock-based compensation, and (iv) other unusual or non‑recurring (income)/expenses, such as impairment charges, severance, costs related to our IPO and costs related to asset acquisitions or one-time professional 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, 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.

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Net income (loss)

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

Depreciation and amortization

148,659 4,631 153,290

Interest expense

Income tax expense

1 2,382 2,383

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

Loss on disposal of assets

56,659 1,477 58,136

Impairment expense 36,907 1,095 38,002

Stock‑based compensation

— 9,100 9,100

Other expense

Other general and administrative expense (1)

Deferred IPO bonus, retention bonus and severance expense

— 13,038 13,038

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

Adjusted EBITDA

$ 174,030 $ (32,567) $ 141,463

Pumping All Other Total

Year ended December 31, 2019

Net income (loss)

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

Depreciation and amortization

139,348 5,956 145,304

Interest expense

51 7,090 7,141

Income tax expense

Loss (gain) on disposal of assets

— 50,494 50,494

Loss on disposal of assets

106,178 633 106,811

Impairment expense — 3,405 3,405

Stock‑based compensation

— 7,776 7,776

Other expense

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

$ 533,760 $ (14,691) $ 519,069

Pumping All Other Total

Year ended December 31, 2018

Net income (loss)

$ 253,196 $ (79,334) $ 173,862

Depreciation and amortization

83,404 4,734 88,138

Interest expense

— 6,889 6,889

Income tax expense

— 51,255 51,255

Loss on disposal of assets

59,962 (742) 59,220

Stock‑based compensation

— 5,482 5,482

Other expense

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Deferred IPO bonus

1,832 977 2,809

Adjusted EBITDA

$ 398,396 $ (9,873) $ 388,523

Other general and administrative expense primarily relates to nonrecurring professional fees paid to external consultants in connection with the Expanded Audit Committee Review and advisory services in 2019, and legal settlements in 2018 and 2017.

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(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.

Results of Operations

We conduct our business through five operating segments:

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

We conduct our business through three operating segments:

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 may have been impacted by the Pioneer Pressure Pumping Acquisition which was consummated on December 31, 2018.

The acquisition cost of the assets was comprised of approximately $110.0 million of cash and 16.6 million shares of our common stock.

In addition, we entered into a real estate lease for a crew camp facility with Pioneer.

The real estate lease for the crew camp was terminated in July 2019.

In connection with the consummation of the transaction, we became a long-term service provider to Pioneer, providing pressure pumping and related services for a term of up to ten years.

The Pioneer Pressure Pumping Acquisition resulted in an additional 510,000 HHP being deployed at the beginning of 2019.

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, 2020 Compared to Year Ended December 31, 2019

($ in thousands, except percentages)

Year Ended December 31,

Year Ended December 31, Change

2020 2019 Variance %

Revenue $ 789,232 $ 2,052,314 $ (1,263,082) (61.5) %

Cost of services (1)

584,279 1,470,356 (886,077) (60.3) %

General and administrative expense (2)

86,768 105,076 (18,308) (17.4) %

Depreciation and amortization 153,290 145,304 7,986 5.5 %

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

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

Adjusted EBITDA (3)

$ 141,463 $ 519,069 $ (377,606) (72.7) %

Adjusted EBITDA Margin (3)

17.9 % 25.3 % (7.4) % (29.2) %

Pressure pumping segment results of operations:

Revenue $ 773,474 $ 2,001,627 $ (1,228,153) (61.4) %

Cost of services $ 570,442 $ 1,428,620 $ (858,178) (60.1) %

2 unchanged sentences

22.5 % 26.7 % (4.2) % (15.7) %

____________________

(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.

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”.

(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.

(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 increased 20.4% , or $347.8 million , to $2,052.3 million for the year ended December 31, 2019 , as compared to $1,704.6 million for the year ended December 31, 2018 .

The increase was primarily attributable to the increase in our effectively utilized fleets from approximately 18.8 active fleets in 2018 to 23.9 in 2019 , and an increase in demand for our pressure pumping services and certain customer activity, specifically driven by the Pioneer Pressure Pumping Acquisition.

The increase in revenue was partly offset by the increase in the number of customers self-sourcing certain consumables like sand.

Our pressure pumping segment revenues increased 20.7% , or $ 343.2 million for the year ended December 31, 2019 , as compared to the year ended December 31, 2018 .

Revenues from services other than pressure pumping increased 9.8% , or approximately $4.5 million , for the year ended December 31, 2019 , as compared to the year ended December 31, 2018 .

The increase in revenues from services other than pressure pumping during the year ended December 31, 2019 , was primarily attributable to the increase in demand for our coiled tubing services.

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.

Cost of Services.

Cost of services increased 15.7% , or $199.8 million , to $1,470.4 million for the year ended December 31, 2019 , from $1,270.6 million during the year ended December 31, 2018 .

Cost of services in our pressure pumping segment increased $ 192.4 million during the year ended December 31, 2019 , as compared to the year ended December 31, 2018 .

The increases were primarily attributable to higher activity levels, coupled with an increase in personnel headcount following the increase in our operations in connection with the Pioneer Pressure Pumping Acquisition.

As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 71.4% for the year ended December 31, 2019 , as compared to 74.5% for the year ended December 31, 2018 .

The decrease in cost of services as a percentage of revenue in our pressure pumping segment is attributed to the increased revenue from operational efficiencies and a favorable change in our cost structure driven by our internal cost control initiatives, a decrease in the cost of certain consumables and an increase in the number of customers self-sourcing sand and other consumables, which resulted in significantly higher realized Adjusted EBITDA margins during the year ended December 31, 2019 .

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.

General and Administrative Expenses.

General and administrative expenses increased 94.7% , or $51.1 million , to $105.1 million for the year ended December 31, 2019 , as compared to $54.0 million for the year ended December 31, 2018 .

The net increase was primarily attributable to the increase in retention bonuses, stock-based compensation, and severance and related expenses of $11.0 million driven primarily by the increase in personnel following the Pioneer Pressure Pumping Acquisition, increase in nonrecurring professional fees of $25.0 million, primarily in connection with the Expanded Audit Committee Review, and net increase in our remaining other general and administrative expenses of approximately $15.1 million .

General and administrative expenses decreased 17.4%, or $18.3 million, to $86.8 million for the year ended December 31, 2020, as compared to $105.1 million for the year ended December 31, 2019.

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.

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 additional property and equipment purchased in connection with the Pioneer Pressure Pumping Acquisition and other equipment put into service during 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.

Impairment Expense.

Impairment expense of $3.4 million , a non-cash expense, was recorded during the year ended December 31, 2019 in connection with our vertical drilling rigs and flowback assets resulting from the depressed demand and negative future near-term outlook for our drilling assets and the shutdown of our flowback operations.

No impairment expense was recorded in the year ended December 31, 2018 .

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.

Loss on Disposal of Assets.

Loss on the disposal of assets increased 80.4% , or $47.6 million , to $106.8 million for the year ended December 31, 2019 , as compared to $59.2 million for the year ended December 31, 2018 .

The increase was primarily attributable to an increase in our hydraulic fracturing fleet size, and greater intensity of jobs as well as the number of jobs completed.

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.

Interest Expense.

Interest expense increased 3.7% , or $0.3 million , to $7.1 million for the year ended December 31, 2019 , as compared to $6.9 million for the year ended December 31, 2018 .

The increase in interest expense was primarily attributable to an increase in our average debt balance in 2019 compared to 2018 .

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 expense was $50.5 million for the year ended December 31, 2019 , as compared to $51.3 million for the year ended December 31, 2018 .

The slight decrease in our provision for income tax expense is attributable to the decrease in pre-tax book income in 2019 compared to 2018 .

Our effective tax rate was relatively flat at 23.7% during the year ended December 31, 2019 compared to 22.8% during the year ended December 31, 2018 .

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.

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.

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, 2019 was approximately $181.2 million and was approximately $16.8 million as of June 19, 2020 .

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.

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.

With the current depressed oil and gas market conditions, we believe our remaining monthly availability under our ABL Credit facility will be adversely impacted by the expected decline in our customers’ activity.

As of December 31, 2019 , our borrowings under our ABL Credit Facility was $130.0 million and our total liquidity was $198.7 million , consisting of cash and cash equivalents of $149.0 million and $49.7 million of availability under our ABL Credit Facility.

As of June 19, 2020 , we had no borrowings under our ABL Credit Facility and our total liquidity was approximately $57.4 million , consisting of cash and cash equivalents of $42.2 million and $15.2 million of availability under our ABL Credit Facility.

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

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.

As of December 31, 2020, we had no borrowings under our ABL Credit Facility and our total liquidity was $120.7 million, consisting of cash and cash equivalents of $68.8 million and $51.9 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.

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.

Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices.

Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business or meet our future long-term liquidity requirements.

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 result of these developments, the Company expects a material adverse impact on the oil field services we provide and our revenue, results of operations and cash flows.

These situations are rapidly changing and additional impacts to the business may arise that we are not aware of currently and the depressed oil and gas industry may take a longer time to recover thereby significantly impacting on revenue, results of operations and cash flows for a longer period of time.

Cash and Cash Flows

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Net cash provided by operating activities

$ 139,124 $ 455,290

Net cash used in investing activities

Net cash provided by (used in) financing activities

$ (94,217) $ (495,299)

Net cash (used in) provided by financing activities

$ (125,171) $ 56,345

Operating Activities

Net cash provided by operating activities was $139.1 million for the year ended December 31, 2020, as compared to $455.3 million for the year ended December 31, 2019.

The net increase of $62.2 million was primarily due to the expansion of our operations following the Pioneer Pressure Pumping Acquisition as well as the associated increase in revenue and cash operating profits, and also impacted by the timing of our receivable collections from our customers and payment to our vendors.

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.

Investing Activities

Net cash used in investing activities increased to $495.3 million for the year ended December 31, 2019 , from $280.6 million for the year ended December 31, 2018 .

The increase was primarily attributable to the cash payment of approximately $110.0 million in connection with the Pioneer Pressure Pumping Acquisition.

In addition, during the year ended December 31, 2019 , we paid approximately $145.3 million for 108,000 HHP of DuraStim® hydraulic fracturing units, ancillary equipment and turbines (including an option payment of $6.1 million to purchase an additional 108,000 HHP of DuraStim® fleets through the end of 2020).

The remaining cash payments in 2019 were primarily incurred in connection with our maintenance capital expenditures and other growth initiatives.

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).

The remaining cash payments in 2019 were incurred in connection with our maintenance capital expenditures and other growth initiatives.

Financing Activities

Net cash provided by financing activities was $56.3 million for the year ended December 31, 2019 , compared to net cash used of $3.7 million for the year ended December 31, 2018 .

Our net cash provided by financing activities during the year ended December 31, 2019 was primarily driven by proceeds from borrowings of $110.0 million to fund our working capital needs and cash payment for fleets acquired in connection with the Pioneer Pressure Pumping Acquisition , proceeds from exercise of equity awards of $1.2 million which was partially offset by cash used in repayment of borrowings of $50.0 million , repayments of insurance financing of $4.5 million and finance lease payment of approximately $0.3 million .

Our net cash used in financing activities during the year ended December 31, 2018 was primarily driven by repayment of borrowings of $80.9 million , repayment of insurance financing of $4.5 million , payment of debt issuance costs of $1.7 million , partially offset by proceeds from borrowings of $77.4 million to fund our working capital needs and proceeds from insurance financing of $5.8 million .

Future Sources and Use of Cash

Capital expenditures for 2020 are projected to be primarily related to maintenance capital expenditures to support our existing assets and growth initiatives, depending on market conditions.

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

Our maintenance capital expenditures are dependent on our operational activity and the intensity on the equipment, among other factors, which could vary throughout the year.

In addition, we have an agreement with our equipment manufacturer granting the Company the option to purchase additional DuraStim® hydraulic fracturing pumps of approximately 108,000 HHP with the purchase option expiring at different times through April 30, 2021.

We believe the cost to acquire the DuraStim® pumps will be comparable to our previously purchased DuraStim® pumps.

In the current economic environment it is not probable we would exercise these options.

We have repaid all our borrowings, as of June 19, 2020 , under our ABL Credit Facility with cash flows from operations and our available cash.

Our objective is to maintain a conservative leverage ratio.

Through June 19, 2020 , we repaid $130.0 million of our borrowings under the ABL Credit Facility.

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.

Credit Facility and Other Financing Arrangements

7 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 ended December 31, 2019 was 4.4% .

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.

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

As of December 31, 2020, 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

We had no off balance sheet arrangements as of December 31, 2019 .

Capital Requirements

We had no material off balance sheet arrangements as of December 31, 2020.

Capital Requirements, Future Sources and Use of Cash

Capital expenditures incurred were $81.2 million during the year ended December 31, 2020, as compared to $400.7 million during the year ended December 31, 2019.

The higher capital expense in 2018 was primarily attributable to the Pioneer Pressure Pumping Acquisition.

We financed the Pioneer Pressure Pumping Acquisition with a combination of cash from operations and borrowings under our ABL Credit Facility and the issuance of 16.6 million of our common shares to Pioneer.

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.

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.

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.

Our cash flows from operations will be generated from services we provide to our customers and idle fees if a customer (Pioneer) decides to idle committed fleets and we are not able to deploy the idled fleets to another customer.

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 and cash flows from operations.

Contractual Obligations

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($ in thousands)

Payment Due by Period

Less than 1 year

More than 5 years

Total 1 year or less More than I year

ABL Credit Facility (1)

Operating leases (2)

Finance leases (2)

Other purchase obligation (3)

1,250 1,250 —

Exclusive of future commitment fees, amortization of deferred financing costs, interest expense or other fees on our revolving credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

However, assuming a weighted average interest rate of 4.4% , and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $5.8 million .

Finance and Operating leases include agreements for various office and yard locations, excluding short-term leases (see Note 17.

Total $ 2,113 $ 1,627 $ 486

____________________

(1) As of December 31, 2020, we had no borrowings under our ABL Credit Facility.

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.

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

Leases and Note 15.

Commitments and Contingencies in the financial statements for additional disclosures, including estimated interest).

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

The agreements with the Sand suppliers require that the Company purchase a minimum volume of sand, constituting substantially all of its sand requirements, from the Sand suppliers, otherwise certain penalties may be charged.

Under certain of the purchase agreements, a shortfall fee applies if the Company purchases less than the minimum volume of sand.

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.

Under one of the purchase agreements, the Company is obligated to purchase a specified percentage of its overall sand requirements, or it must pay the supplier the difference between the purchase price of the minimum volumes under the purchase agreement and the purchase price of the volumes actually purchased.

Our minimum volume commitments under the purchase agreements are either based on a percentage of our total usage or fixed minimum quantity.

O ur agreements with the Sand suppliers expire at different times prior to April 30, 2022.

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

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

Recent Accounting Pronouncements

Disclosure concerning recently issued accounting standards is incorporated by reference to Note 2 of our Consolidated Financial Statements contained in this Annual Report.

Disclosure concerning recently issued accounting standards is incorporated by reference to “Note 2- Significant Accounting Policies” of our Consolidated Financial Statements contained in this Annual Report.

Critical Accounting Policies and Estimates

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Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings.

We primarily retired certain components of equipment such as fluid ends and power ends, rather than entire pieces of equipment, which resulted in a net loss on disposal of assets of $106.8 million , $59.2 million and $39.1 million for the years ended December 31, 2019 , 2018 and 2017 , respectively.

Depreciation of property and equipment is provided on the straight‑line method over estimated useful lives as shown in the table below.

We primarily retired certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment, and the associated loss is recorded in our statement of operations as part of net loss on disposal of assets, which was $58.1 million, $106.8 million and $59.2 million for the years ended December 31, 2020, 2019 and 2018, respectively.

The estimated useful lives and salvage values of property and equipment is subject to key assumptions such as maintenance, utilization and job variation.

Unanticipated future changes in these assumptions could negatively or positively impact our net income.

A 10% change in the useful lives of our property and equipment would have resulted in approximately $14.5 million impact on pre-tax income during the year ended December 31, 2019 .

Unanticipated future changes in these assumptions could negatively or positively impact our net income (loss).

A 10% change in the useful lives of our property and equipment would have resulted in approximately $15.3 million impact on pre-tax loss during the year ended December 31, 2020.

Depreciation of property and equipment is provided on the straight‑line method over estimated useful lives as shown in the table below.

Buildings and property improvements

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The significant assumption is uncertain in that it is driven by future demand for our services and utilization, which could be impacted by crude oil market prices, future market conditions and technological advancements.

Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs, including significant assumptions related to market approach based on recent auction sales or selling prices of comparable equipment.

Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs, including assumptions related to market based on recent auction sales or selling prices of comparable equipment.

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.

We recorded an impairment loss of $1.2 million during the year ended December 31, 2019 related to our drilling assets group, because we believe that our cash flow forecasts were negatively impacted by the depressed vertical drilling market, which led to the idling of the drilling rigs.

Based on observable market inputs, we believe the fair value of the drilling rigs have declined following the continued market decline in the demand for vertical drilling services.

In addition, we recorded an impairment loss of $2.2 million related to our flowback assets group because we believe our future cash flow forecasts were negatively impacted by the decline in the demand for our flowback services and the general depressed market for flowback operations.

If the crude oil market declines or the demand for vertical drilling does not recover, and if the 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 fair value of our drilling assets at December 31, 2019 would result in additional impairment of $0.2 million .

During the first quarter of 2020, management determined the reductions in commodity prices driven by the potential 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.

As a result of the triggering events, we performed recoverability tests on each of the assets groups.

As a result, we expect to recognize impairments and charges in the first quarter of 2020 as follows:

drilling asset group impairment of approximately $1.1 million as a result of our recoverability tests;

write-off of $6.1 million of deposits related to options to purchase additional DuraStim® equipment for which options expire at various times through the end of April 2021 as it is not probable we would exercise our options due to the events described above.

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.

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

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There were no additions to, or disposal of, goodwill during the year ended December 31, 2020.

We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other , on December 31, 2019 , at which time, we determined that the fair value of our hydraulic fracturing reporting unit was substantially in excess of its carrying value.

The hydraulic fracturing operating segment is the only segment which has goodwill at December 31, 2019 .

The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted active fleet revenue and cost assumptions.

Our discounted cash flow analysis includes significant assumptions regarding discount rates, fleet utilization, expected profitability margin, forecasted maintenance capital expenditures, the timing of an anticipated market recovery, and the timing of expected cash flow.

As such, this 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 expect to record a goodwill impairment expense of up to $9.4 million during the first quarter of 2020.

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.

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.

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In determining our need for a valuation allowance as of December 31, 2020, we have considered and made judgments and estimates regarding estimated future taxable income.

These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record a valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income.

These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record additional valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income.

Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates.

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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 7. Management’s Discussion and Analysis