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Item 7. Management’s Discussion and Analysis

2024-03-13 compared with 2023-02-23 · 233 added, 208 removed, 264 unchanged (63% of the section changed)

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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.

We are a leading integrated oilfield service 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 exploration and production (“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 completion services in the region.

Our completion services includes our operating segments comprised of hydraulic fracturing, wireline and cementing operations.

Our hydraulic fracturing operations account for approximately 78.5% 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.

Our total available hydraulic horsepower ("HHP") at December 31, 2023 w as 1,461,500 HHP, which was comprised of 452,500 HHP of our Tier IV Dynamic Gas Blending (“DGB”) dual-fuel equipment, 144,000 HHP of FORCE SM electric-powered equipment and 865,000 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 wellsite.

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 simultaneous hydraulic fracturing ("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 fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at wellsites.

In addition, in 2021 and 2022, we committed to additional conversions of our Tier II equipment to Tier IV DGB, and to purchase new Tier IV DGB dual-fuel equipment.

As such, we entered into conversion and purchase agreements with our equipment manufacturers for a total of 452,500 HHP of Tier IV DGB dual-fuel equipment and as of December 31, 2023, we have received all of the converted and new Tier IV DGB dual-fuel equipment.

In 2022, we entered into three-year electric fleet leases for a total of four FORCE SM electric-powered hydraulic fracturing fleets with 60,000 HHP per fleet.

As of December 31, 2023, we have recei ved 144,000 HHP of FOR CE SM electric-powered equipment.

We currently expect to receive the remaining equipment associated with the second and third fleets and all equipment associated with the fourth fleet in the first half of 2024.

On November 1, 2022, we consummated the acquisition of all of the outstanding limited liability company interests of Silvertip Completion Services Operating, LLC (the “Silvertip Acquisition”), 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, 2023, 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.

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

On December 1, 2023, we consummated the purchase of the assets and operations of Par Five Energy Services LLC (“Par Five”), which provides cementing services in the Delaware Basin, in exchange for $25.4 million of cash .

Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware Basins of 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 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.

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.

We have historically conducted our business through four operating segments:

hydraulic fracturing, wireline, cementing and coiled tubing.

Prior to the fourth quarter of fiscal year 2023, our operating segments met the aggregation criteria and were aggregated into the “Completion Services” reportable segment and our coiled tubing operations (which were divested in September 2022) were shown in the “All Other” category.

Effective as of the fourth quarter of fiscal year 2023, we revised our segment reporting as we determined that our three operating segments no longer met the criteria to be aggregated.

Our Hydraulic Fracturing and Wireline operating segments meet the criteria of a reportable segment.

Our cementing and our divested coiled tubing segments are not material, are not separately reportable, and are included within the “All Other” category.

Prior period segment information has been revised to conform to our current presentation.

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.

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.

On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer Natural Resources USA, Inc.

(“Pioneer”) and Pioneer Pumping Services, LLC in the Pioneer Pressure Pumping Acquisition in exchange for 16.6 million shares of our common stock and $110.0 million in cash, and concurrently entered into a pressure pumping services agreement (the "Pioneer Services Agreement") with Pioneer.

On March 31, 2022, we entered into an amended and restated pressure pumping services agreement (the “A&R Pressure Pumping Services Agreement”) to replace the Pioneer Services Agreement that was entered into in connection with the Pioneer Pressure Pumping Acquisition.

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.

On October 31, 2022, we entered into two pressure pumping services agreements (the “Fleet One Agreement” and the “Fleet Two Agreement”) with Pioneer, pursuant to which we provided 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 was terminated on August 31, 2023.

The Fleet Two Agreement was effective as of January 1, 2023 and was terminated on May 12, 2023.

In October 2023, Pioneer entered into a merger agreement with Exxon Mobil Corporation.

Commodity Price and Other Economic Conditions

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 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.

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.

The oil and gas industry is also impacted by general domestic and international economic conditions such as supply chain disruptions and inflation, war and 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.

Since October 2023, an ongoing conflict between Israel and Palestinian militants in the Israel-Gaza region has led to significant armed hostilities.

The geopolitical and macroeconomic consequences of this conflict remain uncertain, and such events, or any further hostilities in the Israel-Gaza region or elsewhere, could severely impact the world economy, the demand for and price of crude oil and the oil and gas industry generally and may adversely affect our financial condition.

Similarly, the geopolitical and macroeconomic consequences of the Russian invasion of Ukraine, including the associated sanctions, and the adverse impacts of the COVID-19 pandemic in recent years have resulted in volatility in supply and demand dynamics for crude oil and associated volatility in crude oil pricing.

As the global response to the COVID-19 pandemic began to wane, the demand and prices for crude oil increased from the lows experienced in 2020, with the WTI average crude oil price

reaching approximately $94 per barrel in 2022, the highest average price in the prior nine years.

However, in 2023, the WTI average crude oil price declined to approximately $78 per barrel.

We believe that the volatility of crude oil prices in recent years has been partly driven by declines in crude oil supplies, concerns over sanctions resulting from Russia's invasion of Ukraine, concerns over a potential disruption of Middle Eastern oil supplies resulting from the ongoing conflict between Israel and Palestinian militants in the Israel-Gaza region, slower crude oil production growth due to the lack of reinvestment in the oil and gas industry in the last two years, recent OPEC+ production cuts of approximately 1.3 million barrels per day and concerns of a potential global recession resulting from high inflation and interest rates.

With the significant increase in global crude oil prices from 2021, including the WTI crude oil price, there was a significant increase in the Permian Basin rig count from approximately 179 at the beginning of 2021 to approximately 353 at the end of 2022, according to the Baker Hughes Company (“Baker Hughes”).

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

However, we have recently experienced a 13% decrease in the rig count in 2023 to 309 at the end of 2023 which resulted in a reduction in the demand for completion services and pressure on pricing of our services.

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.

We cannot predict any future trends in the rate of inflation and crude oil prices.

A significant increase in or continued high levels of inflation, to the extent we are unable to timely pass-through the cost increases to our customers, or further declines in crude oil prices 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.

"Risk Factors—We may be adversely affected by the effects of inflation."

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

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.

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

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

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

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.

We have transitioned our hydraulic fracturing available equipment portfolio from approximately 10% lower emissions equipment in 2021 to approximately 35% in 2022 and 60% in 2023, and expect to increase to approximately 65% by the end of the first half of 2024.

To the extent any of our customers have certain expectations or requirements with respect to emissions reductions from their contractors, if we are unable to continue quickly transitioning to lower emissions equipment, the demand for our services could be adversely impacted.

If the Permian Basin rig count and market conditions improve, including improved pricing for our services 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.

If the rig count or 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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• 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 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.

• our average effectively utilized hydraulic fracturing fleet count was approximately 15 active fleets, consistent with 15 active fleets in 2022;

• successfully integrated our wireline business with our existing hydraulic fracturing and cementing businesses;

• deployed two FORCE SM electric-powered hydraulic fracturing fleets with a total capacity of 120,000 HHP, and transitioned 452,500 HHP of our equipment portfolio to lower emissions, Tier IV DGB dual-fuel equipment.

By adding two additional electric fleets by the end of the first half of 2024, our available equipment portfolio is expected to be comprised of approximately 65% lower emissions (FORCE SM electric and Tier IV DGB dual-fuel), and 35% conventional diesel equipment;

• published our inaugural sustainability report, which describes our commitment to building a sustainable business that supports the safe, reliable production of the energy the world needs by offering competitive, value-driving services to customers, while benefitting our shareholders, communities, and other stakeholders;

• on December 1, 2023, we consummated the purchase of the assets and operations of Par Five, which provides cementing services in the Delaware Basin.

2023 Financial Highlights

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• cost of services (exclusive of depreciation and amortization) increased $249.0 million or 28.2% to $1,131.8 million, as compared to $882.8 million for the year ended December 31, 2022;

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;

cost of services as a percentage of revenue increased to 69.4% in 2023 compared to 69.0% for the year ended December 31, 2022;

• general and administrative expenses, inclusive of stock-based compensation, increased $2.6 million, or 2.3% to $114.4 million, as compared to $111.8 million for the year ended December 31, 2022;

• 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;

• no impairment expense was recorded during the year December 31, 2023, compared to $57.5 million impairment expense recorded during the year ended December 31, 2022 related to our DuraStim® electric-powered hydraulic fracturing equipment;

• net income was $85.6 million, compared to $2.0 million for the year ended December 31, 2022.

Diluted net income per common share was $0.76, compared to $0.02 for the year ended December 31, 2022.

Adjusted EBITDA of approximately $404.0 million increased 27.6%, compared to $316.6 million for the year ended December 31, 2022 (see reconciliation of Adjusted EBITDA to net income in the subsequent section "How We Evaluate Our Operations");

• our total liquidity was $134.4 million , consisting of cash, cash equivalents and restricted cash of $33.4 million and remaining availability of $101.0 million under our ABL Credit Facility;

$45.0 million of borrowings as of December 31, 2023 under our ABL Credit Facility;

• the Company repurchased and retired 5.8 million shares of common stock for an aggregate of $51.7 million, an average price per share of $8.93 including commissions, under the repurchase program.

As of December 31, 2023, $48.3 million remained authorized for future repurchases of common stock under the repurchase program.

• In connection with the review of our power ends estimated useful life, effective January 1, 2023, we are writing off the remaining book value of power ends that prematurely fail as accelerated depreciation.

These write-off amounts were $12.5 million, $11.8 million, $8.4 million and $6.0 million for the three months ended March, 31, 2023, June 30, 2023, September 30, 2023 and December 31, 2023, respectively.

However, to conform to prior year presentation, we have presented these write-off amounts within loss on disposal of assets for the year ended December 31, 2023.

In 2022 and 2021, we wrote off the remaining book value of prematurely failed and disposed of power ends to loss on disposal of assets.

Our Assets and Operations

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.

Completion services includes our hydraulic fracturing, wireline and cementing operations.

We primarily provide these services to E&P comp anies in the Permian Basin.

During the year ended December 31, 2023, our hydraulic fracturing, wireline and cementing operations accounted for 78.5%, 14.1% and 7.4% 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 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 Completion Services segment, and more specifically, by providing hydraulic fracturing services to our customers.

We generate revenue through our completion services, 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.

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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.

These completion services are complementary to each other and are undertaken in unison with hydraulic fracturing services.

They 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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Prices are affected by many factors beyond our control.

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 2023, the W TI oil price was approximately $78 per barrel.

The average WTI oil price per barrel was approximately $78 , $94 and $68 for the years ended December 31, 2023, 2022 and 2021, respectively.

In January 2024, the WTI oil price was approximately $74 p er barrel.

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

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

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

We monitor 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 Baker Hughes rig count information was as follows:

Year Ended December 31,

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Total 335 335 240

Average Permian Basin rig count to U.S rig count 46.3 % 50.5 % 51.0 %

Average Permian Basin rig count to U.S.

rig count 48.7 % 46.3 % 50.5 %

Costs of Conducting our Business

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Direct lab or costs amounted to 28.7% and 27.7% of total costs of service for the years ended December 31, 2023 and 2022, respectively.

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

The increase in our direct labor costs percentage is driven by wage adjustments and higher headcount resulting from business acquisitions.

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

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Other direct costs were 38.4% and 38.7% of total costs of service for the years ended December 31, 2023 and 2022, respectively.

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 nonrecurring legal settlement 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, (iii) other expense/(income) and (iv) other unusual or nonrecurring (income)/expenses, such as impairment charges, retention bonuses, severance, costs related to asset acquisitions, insurance recoveries, one-time professional fees and legal settlements.

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

Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (income) expenses and items outside the control of our management team (such as income taxes).

Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income (loss), operating income (loss), cash flow from operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles in the United States of America ( " GAAP " ).

Note Regarding Non‑GAAP Financial Measures

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 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.

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

The following tables provide a reconciliation of Adjusted EBITDA to the GAAP financial measure of net income (loss) for each of our reportable segments for the specified periods (in thousands):

Hydraulic Fracturing

Wireline All Other

Year ended December 31, 2023

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

Net income $ 131,343 $ 42,051 $ 17,882

Depreciation and amortization 156,057 18,762 5,845

125,867 2,241 128,108

Interest expense

1,605 — 1,605

Income tax expense 5,356 — 5,356

Loss on disposal of assets 71,756 562 796

Impairment expense 57,454 — 57,454

Stock‑based compensation

21,881 — 21,881

Other income (2) (3)

(11,582) — (11,582)

Other expense (1)

Other general and administrative expense

8,460 — 8,460

Severance expense 1,111 17 1,128

Retention bonus and severance expense 635 555 100

Adjusted EBITDA

$ 366,809 $ 61,930 $ 24,665

Services All Other Total

Hydraulic Fracturing Wireline All Other

Year ended December 31, 2022

Net loss $ (51,189) $ (2,996) $ (54,185)

Net income (loss) $ 71,697 $ 5,388 $ (7,865)

Depreciation and amortization

117,753 2,619 7,329

Interest expense

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

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

Stock‑based compensation

11,519 — 11,519

Impairment expense (2)

Loss (gain) on disposal of assets 88,765 (77) 13,953

Other income (3)

Other general and administrative expense (1)

(2,668) (4) —

Other general and administrative expense (4)

Severance expense 1,061 — 17

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$ 339,186 $ 7,926 $ 13,434

Services All Other Total

Hydraulic Fracturing Wireline All Other

Year ended December 31, 2021

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124,999 — 8,076

Interest expense

2,383 — 2,383

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

Loss on disposal of assets

56,584 1,552 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)

13,038 — 13,038

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

Severance expense — — 30

Adjusted EBITDA

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____________________

(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.

(1) Includes settlement expenses resulting from routine audits.

(2) Represents expense in connection with the impairment of our DuraStim® electric-powered hydraulic fracturing equipment.

(3) Includes $2.7 million of non-cash income from fixed asset inventory received as part of a settlement of warranty claims with an equipment manufacturer.

(4) Includes legal settlement to a vendor and other legal matters, net of reimbursement from insurance carriers.

Results of Operations

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.

In 2023, we conducted our business through three operating segments:

hydraulic fracturing, wireline, and cementing.

Our cementing operating segment and coiled tubing operations are shown in the “All Other” category for segment reporting purposes.

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, 2023 Compared to Year Ended December 31, 2022

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2023 2022 Variance %

Revenue $ 1,279,701 $ 874,514 $ 405,187 46.3 %

Hydraulic Fracturing $ 1,280,523 $ 1,143,216 $ 137,307 12.0 %

Wireline 229,599 31,188 198,411 636.2 %

All Other (1)

120,277 105,297 14,980 14.2 %

Total revenue 1,630,399 1,279,701 350,698 27.4 %

Cost of services (2)

Hydraulic Fracturing 886,157 776,021 110,136 14.2 %

Wireline 155,357 21,141 134,216 634.9 %

All Other (1)

90,287 85,658 4,629 5.4 %

Total cost of services 1,131,801 882,820 248,981 28.2 %

General and administrative expense (3)

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Other expense (income) 9,533 (11,582) 21,115 182.3 %

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

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

Income tax expense 29,868 5,356 24,512 457.7 %

Net income $ 85,634 $ 2,030 $ 83,604 4,118.4 %

Adjusted EBITDA (4)

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24.8 % 24.7 % 0.1 % 0.4 %

Completion Services segment results of operations:

Hydraulic Fracturing segment results of operations:

Revenue $ 1,280,523 $ 1,143,216 $ 137,307 12.0 %

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(1) Includes our cementing and our disposed of coiled tubing operations.

(2) Exclusive of depreciation and amortization.

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(4) 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 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.

" Included in our Adjusted EBITDA is reservation and idle fees of $0 and $27.0 million for the years ended December 31, 2023 and 2022, respectively.

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

Revenue increased 27.4%, or $350.7 million, to $1,630.4 million for the year ended December 31, 2023, as compared to $1,279.7 million for the year ended December 31, 2022.

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.

Revenue by reportable segment was as follows:

Hydraulic Fracturing.

Our hydraulic fracturing segment revenues increased 12.0%, or $137.3 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022.

The increase was primarily attributable to the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, and improved pricing.

Our effectively utilized hydraulic fracturing fleet count was flat at 15 active fleets for the year ended December 31, 2023, as in the year ended December 31, 2022.

The effectively utilized fleet count is determined by dividing the total number of days our fleets were actively working at wellsites during the month by 25 days (predetermined number of expected active work days in the month).

Our revenue for the years ended December 31, 2023 and December 31, 2022 included reservation fees charged to a customer of approximately $0 and $27.0 million, respectively.

Our wireline segment revenue increased 636.2%, or $198.4 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022.

The increase was primarily attributable to a full year of activity for the year ended December 31, 2023 compared to only 61 days of activity during year ended December 31, 2022 since the wireline business was acquired on November 1, 2022.

Revenue from the All Other category comprising of our cementing and our disposed of coiled tubing operations increased 14.2%, or $15.0 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022.

The increase was primarily attributable to the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, and improved pricing, partially offset by the discontinuation of our coiled tubing operations effective September 1, 2022.

Cost of Services.

Cost of services increased 28.2%, or $249.0 million, to $1,131.8 million for the year ended December 31, 2023, from $882.8 million during the year ended December 31, 2022.

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.

Cost of services by reportable segment was as follows:

Hydraulic Fracturing.

C ost of services for our hydraulic fracturing segment increased $110.1 million during the year ended December 31, 2023, as compared to the year ended December 31, 2022.

The increase was primarily attributable to increased activity levels resulting from the increased demand for our services as compared to 2022, and the impact of general cost inflation.

As a percentage of hydraulic fracturing revenues (including reservation fees), hydraulic fracturing cost of services increased to 69.2% for the year ended December 31, 2023, as compared to 67.9% for the year ended December 31, 2022.

Excluding reservation fees revenue of $0 and $27.0 million for the years ended December 31, 2023 and 2022, respectively, our hydraulic fracturing cost of services as a percentage of hydraulic fracturing revenues for the years ended December 31, 2023 and 2022 was approximately 69.2% and 69.5%, respectively.

The decrease was a result of increased operational efficiencies and improved customer pricing, partially offset by costs of $38.0 million associated with the replacement of fluid ends during the year ended December 31, 2023 .

Fluid ends were capitalized and depreciated in 2022.

Effective January 1, 2023, the Company commenced expensing fluid ends as part of cost of services rather than capitalizing fluid ends as part of property and equipment as a result of the change in estimated useful life.

Our wireline segment cost of services increased 634.9%, or $134.2 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022.

The increase was primarily attributable to a full year of activity for the the year ended December 31, 2023 compared to only 61 days of activity during year ended December 31, 2022 since the wireline business was acquired on November 1, 2022.

Cost of services for the All Other category comprising of our cementing and our disposed of coiled tubing operations increased 5.4%, or $4.6 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022.

The increase was primarily attributable to increased activity levels resulting from the increased demand for our services as compared to 2022, and the impact of general cost inflation, partially offset by the discontinuation of our coiled tubing operations effective September 1, 2022.

General and Administrative Expenses.

General and administrative expen ses increased 2.3%, or $2.6 million, to $114.4 million for the y ear ended December 31, 2023, as compared to $111.8 million for the year ended December 31, 2022.

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.

The net increase was primarily attributable to (i) a $6.3 million increase in payroll and related expenses, (ii) a $5.1 million increase in utilities, advertising and other office expenses, (iii) a $2.1 million increase in travel expenses, and (iv) a $0.4 million net increase in

other general and administrative expenses, partially offset by (i) a $7.4 million decrease in stock-based compensation expense primarily attributable to non-recurring incremental stock-based compensation in 2022 resulting from the acceleration of stock awards in connection with the resignation of former executives and (ii) a $3.9 million decrease in one-time legal settlement expenses.

Excluding nonrecurring and non-cash items ( i.e., stock-based compensation of $14.5 million, legal settlements (net of insurance reimbursements) of $0.7 million, transaction expenses of $2.3 million, and retention bonuses and severance expenses of $2.3 million), general and administrative expenses were $94.6 million for the year ended December 31, 2023, as compared to $80.3 million for the year ended December 31, 2022.

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 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.

Depreciation and amortization increased 41.2%, or $52.8 million, to $180.9 million for the yea r ended December 31, 2023, as compared to $128.1 million for the year ended December 31, 2022.

The increase was primarily attributable to the increase in our fixed asset base as of December 31, 2023.

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, 2023.

During the year ended December 31, 2022, we recorded $57.5 million in connection with the impairment of our DuraStim® electric powered hydraulic fracturing equipment, which is included in our Hydraulic Fracturing reportable 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 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.

Loss on the disposal of assets decreased 28.5%, or $29.1 million, to $73.0 million for the year ended December 31, 2023, as compared to $102.1 million for the year ended December 31, 2022.

The decrease was primarily attributable to a loss of approximately $13.8 million from the disposal of our coiled tubing assets on September 1, 2022 and the Company expensing costs associated with replacement of fluid ends as part of cost of services resulting from the change in estimated useful life effective January 1, 2023, partially offset by losses incurred from the decommissioning/conversion of certain hydraulic fracturing equipment and the write-off of certain hydraulic fracturing equipment as a result of an accidental fire at a wellsite in March 2023.

Interest Expense.

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.

Interest expense increased to $5.3 million for the yea r ended December 31, 2023, as compared to $1.6 million for t he year ended December 31, 2022.

The increase was primarily attributable to higher average outstanding borrowings under our ABL Credit Facility during the year ended December 31, 2023 and the addition of a finance lease for certain power generation equipment in August 2023.

Other Expense (Income).

Other expense was approximately $9.5 million for the year ended December 31, 2023, as compared to other income of $11.6 million for the year ended December 31, 2022.

Other expense during the year ended December 31, 2023 is primarily comprised of settlement expenses resulting from routine audits and one-time health insurance costs totaling approximately $7.4 million, and a $2.5 million unrealized loss on short-term investment.

Other income during the year ended December 31, 2022 is comprised of a $10.7 million net tax refund of sales, excise and use taxes and $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.

Total income tax expense was $29.9 million resulting in an effective tax rate of 25.9% for the year ended December 31, 2023, as compared to $5.4 million or an effective tax rate of 72.5% for the year ended December 31, 2022.

The change in income tax expense recorded during the year ended December 31, 2023, compared to the year ended December 31, 2022, is primarily attributable to the difference in the impact of nondeductible expenses on the pre-tax income for 2023, as compared to 2022.

Liquidity and Capital Resources

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.

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

Our cash is primarily used to fund our operations, support growth opportunities, fund share repurchases under our share repurchase program and satisfy future debt payments.

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

Our Borrowing Base (as defined below), as redetermined monthly, is tied to the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base), in each case, depending on the credit ratings of our accounts receivable counterparties, less customary reserves.

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 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.

We received advance payments from a customer for our services, and the amount outstanding in connection with the advance payments was $19.2 million and $10.0 million as of December 31, 2023 an d 2022, respectively.

These amounts included restricted cash of $0 and $10.0 million as of December 31, 2023 an d 2022, respectively.

As of December 31, 2023, our borrowings under our ABL Credit Facility were $45.0 million and our total liquidity was $134.4 million, consisting of cash and cash equivalents of $33.4 million and $101.0 million of availability under our ABL Credit Facility.

On May 17, 2023, the Board authorized and the Company announced a share repurchase program that allows the Company to repurchase up to $100 million of the Company's common stock beginning immediately and continuing through and including May 31, 2024.

The shares may be repurchased from time to time in open market transactions, block trades, accelerated share repurchases, privately negotiated transactions, derivative transactions or otherwise, certain of which may be made pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Exchange Act, as amended, in compliance with applicable state and federal securities laws.

The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management's assessment of the intrinsic value of the Company's common stock, the market price of the Company's common stock, general market and economic conditions, available liquidity, compliance with the Company's debt and other agreements, applicable legal requirements, and other considerations.

The Company is not obligated to purchase any shares under the repurchase program, and the program may be suspended, modified, or discontinued at any time without prior notice.

The Company expects to fund the repurchases using cash on hand and expected free cash flow to be generated through May 2024.

During the year ended December 31, 2023 , the Company repurchased and retired 5.8 million shares of common stock for an aggregate of $51.7 million, an average price per share of $8.93 including commissions, under the repurchase program.

As of December 31, 2023 , $48.3 million remained authorized for future repurchases of common stock under the repurchase program.

As part of our real estate consolidation strategy, we sold our corporate office building and the associated real property in August 2023 for cash proceeds of $4.7 million after commission and closing costs and recognized a gain on disposal of assets of $0.1 million during the year ended December 31, 2023 .

We have subsequently relocated our corporate office to a leased office space.

See "Note 17 - Leases" for further information.

On December 1, 2023, the Company consummated the purchase of the assets and operations of Par Five, which provides cementing services in the Delaware Basin in exchange for cash consideration of $25.4 million.

Par Five’s business complements our existing cementing business and enables us to serve both the Midland and Delaware Basins of the Permian Basin.

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 and to continue with our share repurchases under our share repurchase program or fund future business acquisitions.

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.

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$ (384,127) $ (349,745)

Net cash provided by (used in) financing activities

Net cash (used in) provided by financing activities

$ (46,123) $ 26,260

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Net cash provided by operating activities was $374.7 million for the year ended December 31, 2023, as compared to $300.4 million for the year ended December 31, 2022.

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.

The net increase of $74.3 million was primarily due to the improvement in our net income, resulting from the increase in our existing and new customers' activity levels, resulting in higher demand for completion services, increased operational efficiencies and the addition of wireline operations .

The increase in cash provided by operating activities was also impacted by timing of our receivable collections from our customers and payments to our vendors, partially offset by increases in inventories and prepaid expenses.

Investing Activities

Net cash used in investing activities increased to $384.1 million for the year ended December 31, 2023, from $349.7 million for the year ended December 31, 2022.

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.

The increase was primarily attributable to maintenance capital expenditures and our investment in lower emissions Tier IV DGB dual-fuel equipment (conversion of Tier II equipment to Tier IV DGB equipment and new Tier IV DGB equipment).

The following table summarizes our capital expenditures incurred by reportable segment for the periods indicated:

Year Ended December 31,

(in thousands) 2023 2022

Reportable Segments:

Hydraulic Fracturing $ 294,377 $ 347,757

Wireline 12,203 2,265

All Other (1)

Reconciling Items (2)

Total capital expenditures $ 310,020 $ 365,316

_________________

(1) All Other includes our cementing operating segment and our disposed coiled tubing operations.

(2) Reconciling Items include our corporate facilities.

Financing Activities

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.

Net cash used in financing activities was $46.1 million for the year ended December 31, 2023, compared to net cash provided by of $26.3 million for the year ended December 31, 2022.

The net increase was primarily driven by share repurchases of $51.7 million, repayments of borrowings of $15.0 million and payments of finance lease obligation of $4.7 million.

Credit Facility and Other Financing Arrangements

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.

Our revolving credit facility, as amended and restated in April 2022, prior to giving effect to the amendment to the revolving credit facility in June 2023, had a total borrowing capacity of $150.0 million.

The revolving credit facility had 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 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) $10.0 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.

Under the revolving credit facility we were required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities.

Effective June 2, 2023, the Company entered into an amendment to its amended and restated revolving credit facility the revolving credit facility (as amended and restated in April 2022, as amended in June 2023 and as may be amended further, "ABL Credit Facility").

The amendment increased the borrowing capacity under the ABL Credit Facility to $225.0 million (subject to the Borrowing Base limit), and extended the maturity date to June 2, 2028.

The ABL Credit Facility has a borrowing base of the sum of 85% to 90% of monthly eligible accounts receivable and 80% of eligible unbilled accounts (up to a maximum of 25% of the Borrowing Base) less customary reserves (the "Borrowing Base"), in each case, depending on the credit ratings of our accounts receivable counterparties, as redetermined monthly.

The Borrowing Base as of December 31, 2023, was approximately $152.0 million.

The ABL Credit Facility includes a springing fixed charge coverage ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size or the Borrowing Base or (ii) $15.0 million.

Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities.

Under the ABL Credit Facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens or indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities.

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

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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.

As of December 31, 2023 and 2022 , we had outstanding borrowings under our ABL Credit Facility of $45.0 million and $30.0 million, respectively.

Off Balance Sheet Arrangements

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Capital expenditures incurred were $310.0 million during the year ended December 31, 2023, as compared to $365.3 million during the year ended December 31, 2022.

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.

The significant portion of our total capital expenditures incurred during the year ended December 31, 2023 were 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.

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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 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.

Based on our current plan and projected activity levels for 2024, we expect our capital expenditures to range between $200 million to $250 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 our operations or we invest in new or different 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.

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.

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110,083 33,680 76,403

Finance lease (4)

52,534 19,872 32,662

Sand commitment (5)

17,659 17,659 —

Equipment purchase commitments (5)

Par Five deferred cash consideration (6)

3,180 — 3,180

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

(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.

(3) Includes our leases for FORCE SM electric-powered hydraulic fracturing fleets (240,000 HHP).

We expect to receive the remaining equipment under these leases in the first half of 2024.

(4) Finance lease for certain power generation equipment (70 MW) to support electric-powered hydraulic fracturing equipment .

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

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

(6) Represents the unpaid portion of the purchase consideration on our acquisition of Par Five assets to be used to cover the amount by which the estimated purchase price exceeds the final purchase price, if any.

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

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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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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America.

The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with GAAP.

The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years.

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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 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 $102.1 million , $64.6 million and $58.1 million for the years ended December 31, 2022, 2021 and 2020, respectively.

We primarily retire certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment.

The associated loss is recorded in our statement of operations as part of net loss on disposal of assets, which was $73.0 million , $102.1 million and $64.6 million for the years ended December 31, 2023, 2022 and 2021, respectively.

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

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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 including intangible 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 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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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.

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.

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.

If the crude oil market declines or the demand for our services does n ot recover, and if our equipment remains idle or underutilized, 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 offsetting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment.

In 2022, we recorded impairment expense of $57.5 million on our DuraStim® electric-powered hydraulic fracturing equipment within the hydraulic fracturing operating segment .

Goodwill and Other Intangible Assets

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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.

There were no additions to goodwill during the year ended December 31, 2023.

The wireline operating segment is the only segment with goodwill at December 31, 2023 and 2022.

There were no goodwill impairment losses during the years ended December 31, 2023 and 2022.

We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles—Goodwill and Other , on December 31, 2023, 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.

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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.

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

As of December 31, 2023 and 2022, our goodwill carrying value was $23.6 million and $23.6 million, respectively.

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.

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 during the year ended December 31, 2022.

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

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Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.

Share Repurchases

All shares of common stock repurchased through the Company's share repurchase program are retired upon repurchase.

The Company accounts for the purchase price of repurchased common stock in excess of par value ($0.001 per share of common stock) as a reduction of additional paid-in capital, and will continue to do so until additional paid-in capital is reduced to zero.

Thereafter, any excess purchase price will be recorded as a reduction of retained earnings.

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