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Item 7. Management’s Discussion and Analysis

2023-02-23 compared with 2022-02-25 · 225 added, 197 removed, 247 unchanged (63% 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, 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.

This discussion of our results omits our results of operations and cash flows for the year ended December 31, 2020 and the comparison of our results of operations for the years ended December 31, 2021 and 2020, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022.

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 E&P of North American oil and natural gas resources.

and its subsidiaries.

We are a leading integrated oilfield services company, located in Midland, Texas, focused on providing innovative hydraulic fracturing, wireline and other complementary oilfield completion 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 HHP .

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.

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 completion services in the region.

Our hydraulic fracturing operations account for approximately 89.3% of our total revenues and operations.

Our total available hydraulic horsepower ("HHP") in our hydraulic fracturing operations at December 31, 2022 w as 1,315,000 HHP, which was comprised of 252,500 HHP of our Tier IV DGB equipment and 1,062,500 HHP of conventional Tier II equipment.

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

Our equipment has been designed to handle the operating conditions commonly encountered 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.

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 capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites.

In addition, in September 2021, August 2022 and December 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and purchase of new Tier IV DGB equipment.

As such, we entered into conversion and purchase arrangements with our equipment manufacturers for a total of 362,500 HHP of Tier IV DGB equipment and as of December 31, 2022, we have received 192,500 HHP of the converted and new Tier IV DGB equipment and expect to receive the remaining 170,000 HHP by the second quarter of 2023.

In August 2022 and December 2022, we entered into three-year electric fleet leases for a total of four fleets with 60,000 HHP per fleet.

We expect to take delivery of the electric fleets at different times during the second half of 2023.

On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC, which provides wireline perforation and ancillary services solely in the Permian Basin in exchange for 10.1 million shares of our common stock valued at $106.7 million, $30.0 million of cash, the payoff of $7.2 million of assumed debt, and the payment of certain other closing and transaction costs.

At December 31, 2022, we had 23 wireline units available to provide wireline perforation and ancillary services.

The Silvertip Acquisition positions the Company as a more resilient and diversified completions-focused oilfield services provider headquartered in the Permian Basin.

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.

However, we have 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.

Our hydraulic fracturing, wireline and cementing operations have been aggregated into one reportable segment:

"Completion Services." In connection with our divestiture of our coiled tubing operations and the Silvertip Acquisition, we have revised our reportable segment presentation from Pressure Pumping to Completion Services and have restated prior periods accordingly.

Our now discontinued coiled tubing, drilling and flowback operations were aggregated into the "All Other" category.

For additional financial information on our reportable segments presentation, please see reportable segment information in Part II - Item 8, "Financial Statements and Supplementary Data."

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 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.

Pioneer can increase the number of committed fleets prior to December 31, 2022.

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 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 future financial condition, results of operations and cash flows.

In connection with the acquisition, we became a long-term service provider to Pioneer under the Pioneer Services Agreement , with a term of up to 10 years for providing pressure pumping and related services, with Pioneer having the right to terminate the agreement, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026 and the right to increase the number of committed fleets prior to December 31, 2022.

Under the agreement, the Company was entitled to receive compensation if Pioneer were to idle committed fleets ("idle fees");

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

This agreement was superseded by the agreement below.

On March 31, 2022, we entered into an amended and restated A&R Pressure Pumping Services Agreement in place of the Pioneer Services Agreement.

The A&R Pressure Pumping Services Agreement, which was effective from January 1, 2022 to December 31, 2022, reduced the number of contracted fleets from eight fleets to six fleets, modified the pressure pumping scope of work and pricing mechanism for contracted fleets, and replaced the idle fees arrangement with equipment reservation fees (the "Reservation fees").

As part of the Reservation fees arrangement, the Company was entitled to receive compensation for all eligible contracted fleets that were made available to Pioneer at the beginning of every quarter in 2022 through the term of the A&R Pressure Pumping Services Agreement.

This agreement expired at the conclusion of its term and was replaced by the Fleet One Agreement and Fleet Two Agreement described below.

On October 31, 2022, we entered into the Fleet One Agreement and the Fleet Two Agreement with Pioneer, pursuant to which we will provide hydraulic fracturing services with two committed fleets, subject to certain termination and release rights.

The Fleet One Agreement was effective as of January 1, 2023 and will terminate on August 31, 2023.

The Fleet Two Agreement was effective as of January 1, 2023 and was originally planned to terminate on the one year anniversary of the date on which the fleet dedicated thereunder converted from a Tier II diesel Simul-Frac fleet to a Tier IV dual fuel zipper fleet, which was expected to occur in May 2023.

In February 2023, Pioneer provided the Company notice (i) stating that Pioneer intended to release Fleet Two effective upon the completion of operations on the pad where the performance of Services (as defined in the Fleet Two Agreement) is in progress on May 12, 2023 and (ii) requesting that the Company agree to the termination of the Fleet Two Agreement as of the Release Date.

The Company agreed with such request, and, as a result, the Fleet Two Agreement will be terminated as of the Release Date.

Commodity Price and Other Economic Conditions

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 has traditionally been volatile and is characterized 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.

The global public health crisis associated with the COVID-19 pandemic has had an adverse effect on global economic activity and the oil and gas industry in 2020 and 2021.

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.

In light of the COVID-19 pandemic, most companies, including our customers in the Permian Basin, reacted by closely managing their operating budget and exercising capital discipline in 2020 and 2021.

In February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities.

As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals.

This conflict, and the resulting sanctions, has contributed to significant increases and volatility in the prices for oil and natural gas.

The geopolitical and macroeconomic consequences of this invasion and associated sanctions remain uncertain, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and the oil and gas industry and may adversely affect our financial condition.

The Russia-Ukraine war, and the adverse impacts of the COVID-19 pandemic in recent years, including inflation, have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing.

In 2022, WTI average crude oil price was approximately $94 per barrel, which is the highest average price in the last nine years.

We believe that the recent surge in global crude oil prices is partly due to the lack of reinvestment in the oil and gas industry in the last two years, and increased demand for oil and gas products, coupled with the adverse impact of the Russia-Ukraine war, which has led to various sanctions on Russian crude oil supply and businesses.

With the significant increase in global crude oil prices, including WTI crude oil prices, there has been an increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of December 2022, according to Baker Hughes.

Following the increase in rig count and WTI crude oil price, the oilfield service industry has experienced increased demand for its completion services, and improved pricing.

As a result of the growing demand for completion services and significant cost inflation across the industry, we negotiated pricing increases with certain of our customers for our completion services, depending on job design.

Although we are currently operating in an improved pricing environment compared to 2020 and 2021, the rapid increase in cost inflation and supply chain tightness could adversely impact our future profitability.

inflation rate has been steadily increasing since 2021.

These inflationary pressures have resulted in and may result in additional increases to the costs of our oilfield goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

Sustained levels of high inflation have likewise caused the U.S.

Federal Reserve and other central banks to increase interest rates, and to the extent elevated inflation remains, we may experience further cost increases for our operations, including labor costs and equipment.

We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to timely pass-through the cost increases to our customers, would negatively impact our business, financial condition and results of operations.

See Part II, Item 1A.

Risk Factors— " Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

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.

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

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.

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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.

We have transitioned our hydraulic fracturing equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022, and expect to increase to approximately 65% in 2023.

The Permian Basin rig count increase, demand for oil and gas products, 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 continue 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 or decline in the future, 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.

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Over the course of the year ended December 31, 2022:

• 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;

• improved pricing and increased operational efficiency at wellsites ;

• our average effectively utilized fleet count was approximately 15 active fleets, a 25% increase from approximately 12 active fleets in 2021;

• 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 entered into a lease agreement for four electric fleets with 60,000 HHP per fleet, and we transitioned 162,500 HHP of our equipment portfolio to lower emissions, Tier IV DGB equipment.

In 2023, our equipment portfolio is expected to be comprised of approximately 65% lower emissions (electric and Tier IV DGB), and 35% conventional diesel equipment;

• we entered into a contract with a customer for the use of one of our electric hydraulic fracturing fleets to provide committed services for a period of three years after we take delivery of the fleet;

• on November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC, which provides wireline perforation and ancillary services solely in the Permian Basin.

2022 Financial Highlights

Financial highlights for the year ended December 31, 2022:

• 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;

• 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");

• 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:

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 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, 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.

• revenue increased $405.2 million, or 46.3%, to $1,279.7 million, as compared to $874.5 million for the year ended December 31, 2021;

• cost of services (exclusive of depreciation and amortization) increased $220.6 million or 33.3% to $882.8 million, as compared to $662.3 million for the year ended December 31, 2021;

cost of services as a percentage of revenue decreased to 69.0% in 2022 compared to 75.7% for the year ended December 31, 2021;

• general and administrative expenses, inclusive of stock-based compensation, increased $28.8 million, or 34.8% to $111.8 million, as compared to $82.9 million for the year ended December 31, 2021;

• the total impairment expense recorded during the year December 31, 2022 was approximately $57.5 million related to our DuraStim® equipment, compared to no impairment expense recorded during the year ended December 31, 2021;

• net income was $2.0 million, compared to a net loss of $54.2 million for the year ended December 31, 2021.

Diluted net income per common share was $0.02, compared to diluted net loss per common share of $0.53 for the year ended December 31, 2021.

Adjusted EBITDA of approximately $316.6 million increased 134.5%, compared to $135.0 million for the year ended December 31, 2021 (see reconciliation of Adjusted EBITDA to net income (loss) in the subsequent section "How We Evaluate Our Operations") and margins increased 930 basis points;

• our total liquidity was $155.2 million, consisting of cash, cash equivalents and restricted cash of $88.9 million and remaining availability of $66.3 million under our ABL Credit Facility;

• $30.0 million of borrowings as of December 31, 2022 under our ABL Credit Facility.

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 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.

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

During the year ended December 31, 2022, our hydraulic fracturing, cementing and wireline operations accounted for 89.3%, 7.2% and 2.4% of our total revenue, respectively.

Our equipment has 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.

In addition to our core Completion Services segment operations, we also offer a suite of complementary services, which we believe 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.

In September 2022, we discontinued our coiled tubing operations and disposed of the coiled tubing assets.

How We Generate Revenue

We generate revenue primarily through our pressure pumping segment, and more specifically, by providing hydraulic fracturing services to our customers.

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

We generate revenue primarily through our Completion Services segment, and more specifically, by providing hydraulic fracturing services to our customers.

We own and operate a fleet of mobile hydraulic fracturing, wireline and cementing units and other auxiliary equipment to perform completion services to E&P companies.

We also provide personnel and services that are tailored to meet each of our customers’ needs.

Hydraulic fracturing operations account for a significant portion of our total revenue.

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 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.

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.

In addition to hydraulic fracturing services, we generate revenue through other completion services that we provide to our customers, including cementing, wireline and other related services.

These completion 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.

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The average WTI oil prices per barrel were approximately $94 , $68 and $39 for the years ended December 31, 2022, 2021 and 2020, respectively.

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

In February 2023, the W TI oil price was approximately $78 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.

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Direct lab or costs amounted to 27.7% and 22.4% of total costs of service for the years ended December 31, 2022 and 2021, respectively.

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

The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount to support current activity levels.

Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our completion services 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 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 increase in our expendable product cost in 2021 was primarily attributable to the increase in our activity levels and higher freight cost.

Expendable product costs comprised approximately 33.6%, and 41.8% of total costs of service for the years ended December 31, 2022 and 2021, respectively.

The percentage decrease in our expendables in 2022 was primarily attributable to certain customers electing to directly source sand and the associated logistics.

Other Direct Costs.

We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses.

Fuel is consumed both in the operation and movement of our hydraulic fracturing fleet and other equipment.

Fuel is consumed both in the operation and movement of our equipment.

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

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Other direct costs were 38.7% and 35.8% of total costs of service for the years ended December 31, 2022 and 2021, respectively.

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

The percentage increase in 2022 was primarily driven by higher recurring repairs and maintenance costs in 2022 compared to 2021.

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) 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.

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 nonrecurring legal settlement and one-time professional and advisory fees.

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

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Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP ( " non-GAAP " ), except when specifically required to be disclosed by GAAP in the financial statements.

We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring (income) expenses and items outside the control of the Company.

We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods and our peer group by removing the effects of our capital structure, asset base, nonrecurring (income) expenses and items outside the control of the Company.

Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA.

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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 (loss) income to Adjusted EBITDA ($ in thousands):

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

Year ended December 31, 2022

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

Net income (loss) $ 19,754 $ (17,724) $ 2,030

Depreciation and amortization

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Interest expense

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

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

1,605 — 1,605

Income tax expense 5,356 — 5,356

Loss on disposal of assets 88,145 14,005 102,150

Impairment expense 57,454 — 57,454

Stock‑based compensation

1 unchanged sentence

Other income (2) (3)

(11,582) — (11,582)

Other general and administrative expense (1)

3 unchanged sentences

$ 318,051 $ (1,461) $ 316,590

Pumping All Other Total

Services All Other Total

Year ended December 31, 2021

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Interest expense

1 2,382 2,383

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

Loss on disposal of assets 64,549 97 64,646

56,659 1,477 58,136

Impairment expense 36,907 1,095 38,002

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 632 — 632

Adjusted EBITDA

$ 134,309 $ 698 $ 135,007

Pumping All Other Total

Services All Other Total

Year ended December 31, 2020

Net income (loss)

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

Net loss $ (99,830) $ (7,190) $ (107,020)

Depreciation and amortization

2 unchanged sentences

2,383 — 2,383

Income tax expense — 50,494 50,494

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

Loss on disposal of assets

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13,038 — 13,038

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

Retention bonus and severance expense 1,140 — 1,140

Adjusted EBITDA

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____________________

(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.

(1) During the years ended December 31, 2022, 2021 and 2020, 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, shareholder litigation, legal settlement to a vendor and other legal matters, net of insurance recoveries.

During the years ended December 31, 2022, 2021

and 2020, we received reimbursement of approxim ately $10.4 million, $9.8 million and $0.6 million, respectively, from our insurance carriers in connection with the SEC investigation and shareholder litigation.

(2) Includes a $10.7 million net tax refund (net of advisory fees) received in March 2022 from the Texas Comptroller of Public Accounts in connection with limited sales, excise and use tax audit of the period from July 1, 2015 through December 31, 2018.

(3) Includes $2.7 million non-cash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer and a $1.6 million unrealized loss on short-term investment.

Results of Operations

We conduct our business through three operating segments:

hydraulic fracturing, cementing and coiled tubing.

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

In 2022, we conducted our business through four operating segments:

hydraulic fracturing, cementing, wireline and coiled tubing .

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

We disposed of our coiled tubing assets and shut down our coiled tubing operations effective September 1, 2022.

The results of our coiled tubing operations prior to September 1, 2022 are reflected in the "All Other" category.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

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Other expense (income) (11,582) (873) 10,709 1,226.7 %

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

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

Income tax expense (benefit) 5,356 (14,252) 19,608 137.6 %

Net income (loss) $ 2,030 $ (54,185) $ 56,215 103.7 %

Adjusted EBITDA (3)

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24.7 % 15.4 % 9.3 % 60.4 %

Pressure pumping segment results of operations:

Completion Services segment results of operations:

Revenue $ 1,266,261 $ 857,642 $ 408,619 47.6 %

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(1) Exclusive of depreciation and amortization.

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

(2) Inclusive of stock‑based compensation.

(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 $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.

" Included in our Adjusted EBITDA is reservation and idle fees of $27.0 million and $9.5 million for the years ended December 31, 2022 and 2021, respectively.

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

Revenue increased 46.3%, or $405.2 million, to $1,279.7 million for the year ended December 31, 2022, as compared to $874.5 million for the year ended December 31, 2021.

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.

Our Completion Services segment revenues increased 47.6%, or $408.6 million for the year ended December 31, 2022, as compared to the year ended December 31, 2021.

The increases were primarily attributable to the significant increase in our existing and new customers' activity levels, resulting in higher demand for completion services and improved pricing, and the additional revenue of $31.2 million following the Silvertip Acquisition.

The increase in demand for our completion services resulted in an approximately 25% increase in our average effectively utilized fleet count to 15 active fleets in 2022 from 12 active fleets in 2021.

Our revenue for the year ended December 31, 2022 included reservation fees charged to a customer of approximately $27.0 million and our revenue for the year ended December 31, 2021 included idle fees charged to a customer of approximately $9.5 million.

The increase in these fees was driven by the A&R Pressure Pumping Services Agreement with Pioneer that required six dedicated fleets throughout 2022.

Revenues from services other than completion services decreased 20.3%, or approximately $3.4 million, for the year ended December 31, 2022, as compared to the year ended December 31, 2021.

The decrease in revenues from services other than completion services during the year ended December 31, 2022, was primarily attributable to the discontinuation of our coiled tubing operations effective September 1, 2022.

Cost of Services.

Cost of services increased 33.3%, or $220.6 million, to $882.8 million for the year ended December 31, 2022, from $662.3 million during the year ended December 31, 2021.

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.

Cost of services in our Completion Services seg ment increased $221.5 million durin g the year ended December 31, 2022, as compared to the year ended December 31, 2021 .

The increases were primarily attributable to the significantly increased activity levels resulting from the increased demand for our services, the Silvertip Acquisition and the impact of general cost inflation.

A s a percentage of Completion Services segment revenues (including idle fees), Completion Services cost of services decre ased to 68.6% for the year ended December 31, 2022, as compared to 75.5% for the year ended December 31, 2021.

Excluding idle fees revenue of $27.0 million and $9.5 million for the years ended December 31, 2022 and 2021, respectively, our Completion Services cost of services as a percentage of Completion Services revenues for the years ended December 31, 2022 and 2021 was approximately 70.1% and 76.4%, respectively.

The decrease in the percentages was a result of increased operational efficiencies, reduction in operational downtime and improved pricing across our customer base.

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 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.

General and administrative expen ses increased 34.8%, or $28.8 million, to $111.8 million for the y ear ended December 31, 2022, as compared to $82.9 million for the year ended December 31, 2021.

The net increase was primarily attributable to (i) an increase in non-recurring legal expenses (net of insurance recoveries) by $11.1 million incurred primarily in connection with shareholder litigation and settlement with a vendor, (ii) an increase in stock-based compensation expense by $10.4 million, primarily attributable to the non-recurring incremental stock-based compensation associated with the acceleration of stock awards upon resignation of former executives, (iii) an increase in consulting and professional fees by $5.2 million, and (iv) the transaction costs related to the Silvertip Acquisition of approximately $2.2 million, partially offset by a net decrease of approximately $0.1 million in other general and administrative expenses.

Depreciation and Amortization.

Depreciation and amortization decreased 4.0%, or $5.3 million, to $128.1 million for the yea r ended December 31, 2022, as compared to $133.4 million for the year ended December 31, 2021.

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.

The decrease was primarily attributable to the decrease in our fixed asset base as of December 31, 2022, partly attributable to the disposal and impairment of certain fixed assets during the period.

Impairment Expense.

During the year ended December 31, 2022, we recorded $57.5 million in connection with the impairment of our DuraStim® assets, which is included in our Completion Services reportable segment.

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 increased 58.0%, or $37.5 million, to $102.1 million for the year ended December 31, 2022, as compared to $64.6 million for the year ended December 31, 2021.

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.

The increase was primarily attributable to the divestiture of our coiled tubing operations.

We recorded a loss of $13.8 million in connection with the divestiture of our coiled tubing operations.

In addition, upon replacement of certain property and equipment, including certain major components like fluid ends and power ends of our completion services equipment, 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 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.

Interest expense increased 161.4%, or $1.0 million, to $1.6 million for the yea r ended December 31, 2022, as compared to $0.6 million for t he year ended December 31, 2021.

The increase was primarily attributable to the partial write down of unamortized capitalized loan origination cost in connection with the modification to our credit facility and interest on borrowings under our ABL Credit Facility.

We had $30.0 million in borrowings under our ABL Credit Facility at the end of 2022 compared to zero at the end of 2021 .

Other (Income) Expense.

Other income increased to approximately $11.6 million for the year ended December 31, 2022, as compared to $0.9 million in income for the year ended December 31, 2021.

The increase in other income is primarily attributable to the net tax refund to the Company of $10.7 million of sales, excise and use taxes, $2.7 million of non-cash income from equipment parts inventory received from an equipment manufacturer as settlement of our warranty claims, partially offset by a $1.6 million unrealized loss on short-term investment.

Income Taxes.

Income tax expense was $5.4 million for the year ended December 31, 2022, as compared to income tax benefit of $14.3 million for the year ended December 31, 2021.

The reduction in income tax benefit recorded during the year ended December 31, 2022 is primarily attributable to the Company recording pre-tax income in 2022 as compared to pre-tax loss in 2021.

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 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 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 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.

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

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

Our restricted cash, which was received from a customer will be used solely for the construction or operation of certain electric hydraulic fracturing equipment.

Our Borrowing Base (as defined below), as redetermined monthly, is tied to 85.0% to 90.0% of eligible accounts receivable.

Changes to our operational activity levels and our customers’ credit ratings 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.

As of December 31, 2022, our borrowings under our ABL Credit Facility were $30.0 million and our total liquidity was $155.2 million, consisting of cash, cash equivalents and restricted cash of $88.9 million and $66.3 million of availability under our ABL Credit Facility.

As of February 20, 2023, our borrowings under our ABL Credit Facility were $30.0 million and our total liquidity was approximately $142.8 million, consisting of cash and cash equivalents of $35.4 million and $107.4 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.

However, with the gradual recovery in the energy industry and the reduced impact of the COVID-19 pandemic, we have seen improvements in the demand for our services and improved pricing, and our liquidity position gradually improved.

However, we expect our overall liquidity to decline if we make additional or accelerate our future capital investments.

Moreover, the current market conditions may be impacted by increasing interest rates and potential economic slowdown or a new outbreak of a COVID-19 variant or other health crisis, which could negatively impact our future operations, revenue, profitability and cash flows.

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.

Cash and Cash Flows

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

Cash, Restricted Cash and Cash Flows

The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2022 and 2021, respectively.

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$ (349,745) $ (104,292)

Net cash used in financing activities

Net cash provided by (used in) financing activities

$ 26,260 $ (7,276)

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Net cash provided by operating activities was $300.4 million for the year ended December 31, 2022, as compared to $154.7 million for the year ended December 31, 2021.

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.

The net increase of $145.7 million was primarily due to the improvement in our net income, resulting from the significant increase in our existing and new customers' activity levels, resulting in higher demand for completion services and improved pricing.

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

Investing Activities

Net cash used in investing activities increased to $349.7 million for the year ended December 31, 2022, from $104.3 million for the year ended December 31, 2021.

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.

The net increase in our cash used in investing activities was primarily attributable to our investment in Tier IV DGB equipment (conversion of Tier II equipment to Tier IV DGB equipment and new Tier IV DGB equipment).

The remaining cash payments in 2022 were incurred in connection with our maintenance capital expenditures, acquisition of our wireline business and other growth initiatives.

Financing Activities

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.

Net cash provided by financing activities was $26.3 million for the year ended December 31, 2022, compared to net cash used of $7.3 million for the year ended December 31, 2021.

The net increase in cash flow from financing activities during the year ended December 31, 2022 was primarily driven by borrowings of $30.0 million under our ABL Credit Facility during 2022 compared to no borrowings during the year ended December 31, 2021.

During the year ended December 31, 2022, there was no cash inflow or outflow in connection with insurance financing, whereas during the year ended December 31, 2021 we had net cash outflow of approximately $5.5 million.

Credit Facility and Other Financing Arrangements

ABL Credit Facility

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.

Our amended and revolving credit facility, as amended in 2018, had a total borrowing capacity of $300.0 million (subject to the borrowing base limit), with a maturity date of December 19, 2023.

The revolving credit facility had a borrowing base of 85% of monthly eligible accounts receivable less customary reserves, as redetermined monthly.

The revolving credit facility included a springing fixed charge coverage ratio to apply when excess availability was less than the greater of (i) 10% of the lesser of the facility size or the borrowing base or (ii) $22.5 million.

Borrowings under the revolving credit facility accrued interest based on a three-tier pricing grid tied to availability, and we had the option to elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranged 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.

Effective April 13, 2022, the Company entered into an amendment and restatement of its revolving credit facility (as a mended and restated, the "ABL Credit Facility").

The ABL Credit Facility decreased the borrowing capacity to $150.0 million (subject to the Borrowing Base (as defined below) limit), with the maturity date extended to April 13, 2027.

The ABL Credit Facility has a borrowing base of 85% to 90%, depending on the credit ratings of our accounts receivable counterparties, of monthly eligible accounts receivable less customary reserves (the "Borrowing Base"), as redetermined monthly.

The Borrowing Base as of December 31, 2022, was approximately $102.3 million.

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Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.

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.

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

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 the Secured Overnight Financing Rate ("SOFR") or the base rate, plus the applicable margin, which ranges from 1.50% to 2.00% for SOFR loans and 0.50% to 1.00% for base rate loans.

The loan origination costs relating to the ABL Credit Facility are classified as an asset in our balance sheet.

As of December 31, 2022, we had borrowings of $30.0 million outstanding under our ABL Credit Facility.

Off Balance Sheet Arrangements

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Capital expenditures incurred were $365.3 million during the year ended December 31, 2022, as compared to $165.2 million during the year ended December 31, 2021.

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.

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

During the year ended December 31, 2022, we increased our capital expenditures to support the increase in our existing and new customers’ activity levels and the transition of our hydraulic fracturing equipment

to lower emissions equipment.

The significant portion of our total capital expenditures in 2022 comprised of maintenance capital expenditures and conversion of our hydraulic fracturing equipment to lower emissions equipment.

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

Capital expenditures for 2023 are projected to be primarily related to capital expenditures to extend the useful life of our existing completion services assets, costs to convert some existing equipment to lower emissions 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.

Based on our current plan and projected activity levels for 2023, we expect our capital expenditures to range betwe en $250 million to $300 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 will continue to evaluate the emissions profile of its equipment 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 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.

Our cash flows from operations will be generated from services we provide to our customers.

Contractual Obligations

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($ in thousands)

Total 1 year or less More than I year

Total 1 year or less More than 1 year

ABL Credit Facility (1)

$ 30,000 $ — $ 30,000

Operating leases (2)(3)

105,398 16,101 89,297

Sand commitment (4)

31,680 31,680 —

Equipment purchase commitments (5)

59,862 59,862 —

Total $ 226,940 $ 107,643 $ 119,297

____________________

(1) As of December 31, 2021, 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.

(1) Exclusive of future commitment fees, amortization of deferred financing costs, interest expense or other fees on our ABL Credit Facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments of future interest rates to be changed.

However, assuming a weighted average interest rate of 5.43% , and that our ABL Credit Facility debt balance remains the same, our estimated annual interest payment will be $1.6 million.

(2) Operating leases exclude short-term leases and other commitments (see Note 16.

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

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

(3) Includes our leases for electric fracturing equipment (240,000 HHP), and power equipment to support electric equipment (70 MW).

This equipment is expected to be delivered in 2023.

(4) Relates to a take-or-pay sand commitment with one of our sand vendors.

(5) Relates to commitments to purchase Tier IV DGB equipment.

We enter into other 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.

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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.

In January 2023, we entered into an equipment lease (the " Power Equipment Lease " ) for certain power generation equipment.

The Power Equipment Lease has not yet commenced.

We currently do not control the assets under the lease and have not taken possession of the assets.

Therefore, the Company has not accounted for the right of use and lease obligation in its balance sheet as of December 31, 2022.

The total estimated contractual commitment in connection with the Power Equipment Lease is approximately $59.6 million.

Recent Accounting Pronouncements

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Impairment of Long-Lived Assets

In accordance with the Financial Accounting Standards Board ( " FASB " ) Accounting Standards Codification ( " ASC " ) 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets , we review the long‑lived assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.

In accordance with the Financial Accounting Standards Board ( " FASB " ) Accounting Standards Codification ( " ASC " ) 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets , we review the long‑lived assets including intangible assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.

An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets.

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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.

In 2022, we recorded impairment expense of $57.5 million on our DuraStim® equipment because it remained idled and there were no near term plans to deploy the DuraStim® equipment to the customers’ wellsite.

Goodwill and Other Intangible Assets

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

Goodwill is not amortized.

We perform an annual impairment test of goodwill as of December 31, or more frequently if circumstances indicate that impairment may exist.

There were no additions to, or disposal of, goodwill during the year ended December 31, 2021.

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.

We perform an annual impairment test of goodwill and intangible assets as of December 31, or more frequently if circumstances indicate that impairment may exist.

In connection with the Silvertip Acquisition, we added $23.6 million of goodwill during the year ended December 31, 2022.

There was no write-off of goodwill during the year ended December 31, 2022.

We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other , on December 31, 2022, at which time, we determined that the fair value of our wireline reporting unit was substantially in excess of its carrying value.

The wireline operating segment is the only segment which has goodwill at December 31, 2022.

The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted equipment utilization, pricing and cost assumptions.

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

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, 2021 because our goodwill carrying value was fully written off during 2020.

The carrying value of goodwill in our balance sheet as of December 31, 2022 was $23.6 million.

Intangible assets consist of customer relationships and trademark/trade name.

In connection with the Silvertip Acquisition, we added intangible assets consisting of $46.5 million of customer relationships and $10.8 million of trademark/trade name.

Intangible assets are amortized on a straight‑line basis with an estimated useful life of ten years.

Our estimated useful life could be sensitive to changes in market conditions and management’s judgment, and are likely to change in the future if certain events occur.

Presently, there are no events or circumstances that will cause us to believe that our estimated useful life for our intangible assets are likely to change.

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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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