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Item 7. Management’s Discussion and Analysis

2022-02-22 compared with 2021-02-24 · 180 added, 198 removed, 190 unchanged (67% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Item 6.

Selected Financial Data” and our audited consolidated and combined financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes appearing elsewhere in this Annual Report.

The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance.

Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report on Form 10-K under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A.

Risk Factors.” We assume no obligation to update any of these forward-looking statements.

This section of this Annual Report on Form 10-K generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019.

For discussion of year ended December 31, 2018, as well as the year ended 2019 compared to the year ended December 31, 2018, refer to Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2019 Annual Report on Form 10-K.

We are an independent provider of hydraulic fracturing services and goods to onshore oil and natural gas E&P companies in North America.

We have grown from one active hydraulic fracturing fleet in December 2011 to approximately 30 active fleets in the first quarter of 2021, including the addition of fleets from the OneStim Acquisition in December 2020.

We are an independent provider of hydraulic fracturing and wireline services and related goods to onshore oil and natural gas exploration and production (“E&P”) companies in North America.

We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin (the “DJ Basin”), the Williston Basin, the San Juan Basin and the Powder River Basin.

Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described in this Annual Report under “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A.

Risk Factors.” Except as required by law, we assume no obligation to update any of these forward-looking statements.

This section of this Annual Report generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020.

For discussion of year ended December 31, 2019, as well as the year ended 2020 compared to the year ended December 31, 2019, refer to Part II, Item 7— “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2020 Annual Report.

We are an independent provider of hydraulic fracturing services and wireline services and related goods to onshore oil and natural gas E&P companies in North America.

We have grown from one active hydraulic fracturing fleet in December 2011 to over 30 active fleets as of December 31, 2021.

We provide our services primarily in the Permian Basin, the Eagle Ford Shale, the DJ Basin, the Williston Basin, the San Juan Basin and the Powder River Basin.

Following the completion of the OneStim Acquisition (as defined below) we now also provide services in the Haynesville Shale, the SCOOP/STACK, the Marcellus Shale, Utica Shale, and the Western Canadian Sedimentary Basin.

Additionally, we operate two sand mines in the Permian Basin.

In response to market conditions described below, in April 2020, we reduced our headcount consistent with the temporary idling of approximately half of our frac fleets that were operating during the first quarter of 2020, while further temporary reductions in active fleets were managed through employee furloughs.

As of December 31, 2020, no employees remained on furlough, and with the completion of the OneStim Acquisition we had a total of approximately 30 active frac fleets and 20 active wireline units.

On December 31, 2020, the Company acquired certain assets and liabilities of Schlumberger Limited’s (“Schlumberger”) OneStim® business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada, including its pressure pumping, pumpdown perforating and Permian frac sand business (such entire business of Schlumberger, “OneStim,” and the portion of OneStim acquired pursuant by the Company, the “Transferred Business”) in exchange for consideration resulting in a total of 66,326,134 shares of Class A common stock, par value $0.01 per share, of the Company (the “Class A Common Stock”) being issued in connection with the transaction (such transaction, the “OneStim Acquisition”;

see Note 3—The OneStim Acquisition to the consolidated and combined financial statements included in “Item 8.

Financial Statements and Supplementary Data”).

Effective December 31, 2020, Schlumberger owned 37% of the issued and outstanding shares of our Common Stock.

The combined company will deliver best-in-class completion services for the sustainable development of unconventional resource plays in the United States and Canada onshore markets.

We believe the following characteristics both distinguish us from our competitors and are the foundations of our business:

forming ongoing partnerships of trust and innovation with our customers;

developing and utilizing technology to maximize well performance;

and promoting a people-centered culture focused on our employees, customers and suppliers.

We have developed strong relationships with our customers by investing significant time in fracture design collaboration, which substantially enhances their production economics.

Our technological innovations have become even more critical as E&P companies have increased the completion complexity and fracture intensity of horizontal wells.

We are proactive in developing innovative solutions to industry challenges, including developing:

(i) our proprietary databases of U.S.

On December 31, 2020, the Company acquired certain assets and liabilities of Schlumberger’s OneStim business, which provides hydraulic fracturing pressure pumping services in onshore United States and Canada, including its pressure pumping, pumpdown perforating and Permian frac sand business, in exchange for consideration resulting in a total of 66,326,134 shares of the Class A Common Stock being issued in connection with the OneStim Acquisition.

As of February 18, 2022, Schlumberger owned 30.5% of the issued and outstanding shares of our Common Stock.

The combined company delivers best-in-class completion services for the sustainable development of unconventional resource plays in the United States and Canada onshore markets.

On October 26, 2021, the Company acquired PropX in exchange for $11.9 million in cash and 3,405,526 shares of Class A Common Stock and 2,441,010 shares of Class B Common Stock, and 2,441,010 Liberty LLC Units, for total consideration of $103.0 million, based on the Class A Common Stock closing price of $15.58 on October 26, 2021, subject to customary post closing adjustments.

The Liberty LLC Units are redeemable for an equivalent number of shares of Class A Common Stock at any time, at the election of the shareholder.

Founded in 2016, PropX is a leading provider of last-mile proppant delivery solutions including proppant handling equipment and logistics software across North America.

PropX offers innovative environmentally friendly technology with optimized dry and wet sand containers and wellsite proppant handling equipment that drive logistics efficiency and reduce noise and emissions.

We believe that PropX wet sand handling technology is a key enabler of the next step of cost and emissions reductions in the proppant industry.

PropX also offers customers the latest real-time logistics software, PropConnect, for sale or as hosted software as a service.

We believe technical innovation and strong relationships with our customer and supplier bases distinguish us from our competitors and are the foundations of our business.

We expect that E&P companies will continue to focus on technological innovation as completion complexity and fracture intensity of horizontal wells increases, particularly as customers are increasingly focused on reducing emissions from their completions operations.

We remain proactive in developing innovative solutions to industry challenges, including developing:

(i) our databases of U.S.

unconventional wells to which we apply our proprietary multi-variable statistical analysis technologies to provide differential insight into fracture design optimization;

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(iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate;

and (iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs.

We foster a people-centered culture built around honoring our commitments to customers, partnering with our suppliers and hiring, training and retaining people that we believe to be the best talent in our field to drive innovation, enabling us to be one of the safest and most efficient hydraulic fracturing companies in the United States.

(iv) our dual fuel dynamic gas blending fleets that allow our engines to run diesel or a combination of diesel and natural gas, to optimize fuel use, reduce emissions and lower costs;

and (v) the successful test of digiFrac™, our innovative, purpose-built electric frac pump that has approximately 25% lower CO2e emission profile than the Tier IV DGB.

In addition, our integrated supply chain includes proppant, chemicals, equipment, logistics and integrated software which we believe promotes wellsite efficiency and leads to more pumping hours and higher productivity throughout the year to better service our customers.

In order to achieve our technological objectives, we carefully manage our liquidity and debt position to promote operational flexibility and invest in the business throughout the full commodity cycle.

Recent Trends and Outlook

During the first quarter of 2020, the emergence of the COVID-19 pandemic placed significant downward pressure on the global economy and oil demand and prices, leading North America operators to announce significant cuts to planned 2020 capital expenditures.

Reduced activity levels led to a plunging rig count and an abrupt curtailment of frac activity.

As a result, OPEC, coupled with production curtailment and a drop in frac activity amongst North America operators, removed significant oil supply from and eased pressure on the market.

During the second half of 2020, OPEC+ suppliers worked to maintain oil production through an agreed upon quota, and North America operators largely remained disciplined in capital spending.

Many operators have announced that they are targeting oil and gas production at the end of 2021 to be consistent with production at the end of 2020.

Early signs of a potential global economic recovery have emerged, driven by the rollout of COVID-19 vaccines, fiscal and monetary stimulus policies, and pent-up demand for goods and services.

These factors support continued improvement in energy demand, while controlled OPEC+ production and discipline amongst E&P operators are supporting oil and gas prices.

WTI prices that have largely stabilized in the second half of 2020, relative to the volatility observed during the second quarter of 2020.

In the fourth quarter of 2020, the price of WTI averaged $42.52 compared with an average of $40.89 for the third quarter of 2020, which was much improved from an average of $27.96 for the second quarter of 2020.

Subsequent to December 31, 2020, the price of WTI has averaged $53.93 through February 16, 2021.

The recovery of energy demand is also reflected in incremental improvement to rig count, as the most recent domestic onshore rig count for North America was 381 rigs reported on February 19, 2021, up from the average in the fourth quarter of 2020 of 297, according to a report by Baker Hughes, a GE company.

The number of total marketable frac fleets has declined significantly from 2019 as the pandemic accelerated the pace of rationalization and cannibalization of frac equipment.

As customer demand is shifting towards next generation technologies that support their emissions and efficiency goals, attrition of older equipment is expected to continue.

This supply shrinkage is a necessary part of moving the market towards balance.

The current pricing dynamic remains challenging, but the Company is having many productive discussions with customers to phase in modest price improvements throughout the year.

The Company was proactive in working with customers as oil prices collapsed, and that partnership works both ways.

With continued uncertainty surrounding the magnitude and timing of oil demand recovery, OPEC+ supply concerns, and ongoing investor pressure for better returns by E&P companies than those achieved over the last decade, we are unable to predict the degree and duration of many factors that may impact our future operating results.

The volatile global economic conditions stemming from the pandemic, the liquidity situation for North American oil producers and the reaction of international oil producers could also exacerbate the risk factors identified in this Annual Report, see also the risk factor relating to COVID-19 disclosed in “Item 1A.–Risk Factors” of this Annual Report.

In response to these developments, the continued duration and ultimate severity of which is unknown, we have taken the following steps to protect our employees, customers and business.

During February 2020, we formed a COVID-19 response team to implement safety procedures and contingency plans at both our customer locations and in our facilities to ensure our ability to continue providing safe and efficient services to our customers, while protecting the health of both employees and customers.

We have been proactive in protecting our business during these unprecedented events.

During the second quarter, we moved quickly to preserve cash and protect our balance sheet and announced strategic actions to align our cost structure with demand for frac services.

Regrettably, for the first time in the Company’s history we undertook a reduction of our personnel and staffed fleet count by approximately 50% and implemented a company-wide furlough plan.

We also suspended variable compensation plans and our 401(k) match, implemented base salary reductions, executive and director compensation reductions, operating cost rationalization, reduction of planned 2020 capital expenditures, and suspended our quarterly dividend.

Further, we implemented a company-wide employee furlough plan that flexes our cost structure to align with the uncertain level of frac demand we experienced during the second and third quarters of 2020.

As of September 30, 2020 all employees were returned from furlough, additionally, effective January 1, 2021 the Company restored 401(k) match and base salaries.

E&P operators are navigating through significant challenges, including industry consolidation, a change in the political climate and capital constraints while maintaining general commitments to flat production with 2021 levels relative to 2020 exit rates.

Dedicated fleet negotiations for 2021, which started in the fall of 2020, saw continued pricing pressure.

However, WTI crude oil prices have improved since the fall bid season.

We believe the frac market will probably experience flat to slightly rising demand for frac services in 2021, based on current visibility into customer plans.

Demand of publicly-traded operators is expected to be relatively level during the year, whereas private operator demand is more likely to be focused on the second half of the year.

Against this backdrop, the Company expects to maintain approximately 30 active frac fleets in the first quarter of 2021, with the potential of adding more

fleets later in the year if the economics improve.

Increased efficiencies that lower our cost of delivery coupled with a gradual, modest rise in frac pricing are the factors that can drive improved fleet profitability.

During the year 2021, the posted WTI price traded at an average of $68.13 per barrel (“Bbl”), as compared to the 2020 average of $39.16 per Bbl and the 2019 average of $56.99 Bbl.

The recovery of energy demand is also reflected in the incremental improvement to rig count, as the average domestic onshore rig count for the United States and Canada was 704 rigs reported in the fourth quarter of 2021, up from the average in the fourth quarter of 2020 of 384, according to a report from Baker Hughes, a GE Company.

E&P operators are responding to oil and gas price signals.

The public operators are maintaining discipline and we expect will show only modest production growth this year, while the private operators are likely reacting more robustly to strong commodity prices.

The transformative work our team accomplished in 2021 positions us well as we believe our industry is beginning an upcycle driven by rapidly tightening markets for oil & gas.

Years of reduced global investment in upstream oil and gas production is now colliding with record global demand for natural gas and natural gas liquids today, and potential record global demand for oil later this year.

Oil and gas are central to the global economy which is well along the way of recovering from the global COVID-19 pandemic.

Within the frac market, two years of supply attrition and cannibalization plus constraints from labor shortages, and a secular shift towards next generation frac fleet technologies has led to tightness in the supply of fleets.

Liberty has focused on finding the right long-term customer partnerships for the future and has been very disciplined in holding our active frac fleet count steady until financial returns justify significant additional fleet deployments.

During 2021, we worked on the integration of the OneStim Acquisition into Liberty, which was exacerbated by COVID-impacted supply chain and difficult labor challenges.

Integration-related costs are still with us today, impacting our financial results.

However, we made improvements in these costs during January 2022, and believe these costs will lessen during 2022.

We expect sequential revenue growth in the first quarter of 2022, along with improvement in our margins as integration costs start to fade away.

We will also benefit from increased pricing in the first quarter of 2022, driven by a pass-through of inflationary costs and higher net service pricing.

We expect modest rises in pricing during subsequent quarters in 2022, along with the opportunity for margin growth associated with lowering our cost of operations and increasing efficiencies.

Increase in Drilling Efficiency and Service Intensity of Completions

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As E&P companies have improved drilling and completion techniques to maximize return and efficiency, we believe that their “break-even oil prices” continue to decline.

These improvements in well economics have kept American Shale oil and gas production competitive even as oil and gas prices have declined.

These improvements in well economics have kept U.S.

Shale oil and gas production competitive even as oil and gas prices have declined.

Liberty has been a significant partner with our customers in driving these continued improvements.

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Unconventional resources are increasingly being targeted through the use of horizontal drilling.

According to Baker Hughes, as reported on February 19, 2021, horizontal rigs accounted for approximately 90% of all rigs drilling in the United States, up from 74% as of December 31, 2014.

According to Baker Hughes, as reported on February 11, 2022, horizontal rigs accounted for approximately 94% of all rigs drilling in the United States and Canada, up from 77% as of December 26, 2014.

Over the past several years, North American E&P companies have benefited from improved drilling economics driven by technologies that reduce the number of days, and the cost, of drilling wells.

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Today the majority of E&P drilling is on multi-well pad development, allowing efficient drilling of multiple horizontal wellbores from the same pad or location.

The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Coras, has dropped from 28 days in 2014 to 20 days in 2020.

The aggregate effect of these improved techniques and technologies have reduced the average days required to drill a well, which according to Lium Research, has dropped from 28 days in 2014 to 17 days in 2021.

Increased complexity and service intensity of horizontal well completions .

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To complete the well, hydraulic fracturing is applied in stages along the wellbore to break-up the resource so that oil and gas can be produced.

As wellbores have increased in length, the number of frac stages and/or the number of perf clusters (frac initiation points) has also increased.

Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the resource.

The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Coras, from six million pounds per well in 2014 to over 16 million pounds per well in 2020.

As wellbores have increased in length, the number of frac stages and/or the number of perforation clusters (frac initiation points) has also increased.

Further, E&P companies have improved production from each stage by applying increasing amounts of proppant in each stage, which better connects the well to the

The aggregate effect of increased number of stages and the increasing amount of proppant in each stage has greatly increased the total amount of proppant used in each well, according to Liberty’s FracTrends database, from six million pounds per well in 2014 to over 18.6 million pounds per well in 2021.

Further efficiency gains are being sought via the “simul-frac” technique.

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This emerging trend will allow operators to complete a pad of wells quicker, thereby shortening the time from spud to first production.

These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and technological innovations to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions.

These industry trends continue to keep our customers as important suppliers to the global oil and natural gas markets, which directly benefit hydraulic fracturing companies like us that have the expertise and innovative technology to effectively service today’s more efficient oilfield drilling activity and the increasing complexity and intensity of well completions.

Given the expected returns that E&P companies have reported for new well development activities due to improved rig efficiencies and increasing well completion complexity and intensity, we expect these industry trends to continue.

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We currently generate revenue through the provision of hydraulic fracturing and wireline services and goods, including sand from our Permian Basin sand mines.

These services and goods are performed under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes.

A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to one year in length.

These services and goods are provided under a variety of contract structures, primarily master service agreements (“MSAs”) as supplemented by statements of work, pricing agreements and specific quotes.

A portion of our statements of work, under MSAs, include provisions that establish pricing arrangements for a period of up to approximately one year in length.

However, the majority of those agreements provide for pricing adjustments based on market conditions.

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The estimated number of fracturing stages to be completed for a particular horizontal well is determined by the customer’s well completion design.

We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing

stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage.

We recognize revenue for each fracturing stage completed, although our revenue per completed fracturing stage varies depending on the actual volumes and types of proppants, chemicals and fluid utilized for each fracturing stage.

The number of fracturing stages that we are able to complete in a period is directly related to the number and utilization of our deployed fleets and size of stages.

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• Adjusted EBITDA;

• Annualized Adjusted EBITDA per Average Active Fleet;

• Net Income Before Taxes;

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We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock based compensation expense, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisition, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves, and non-recurring expenses that management does not consider in assessing ongoing operating performance.

Annualized Adjusted EBITDA per Average Active Fleet is calculated as Adjusted EBITDA annualized, divided by the Average Active Fleets for the same period.

See “—Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with GAAP.

See “Comparison of Non-GAAP Financial Measures” for more information and a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP.

Results of Operations

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Transaction, severance and other costs 15,138 21,061 (5,923)

Depreciation and amortization of intangible assets 180,084 165,379 14,705

(Gain) loss on disposal of assets (411) 2,601 (3,012)

Operating (loss) income (177,026) 103,597 (280,623)

Interest expense, net 14,505 14,681 (176)

Net (loss) income before taxes (191,531) 88,916 (280,447)

Income tax (benefit) expense (30,857) 14,052 (44,909)

Net (loss) income (160,674) 74,864 (235,538)

Net (loss) income attributable to non-controlling interests (45,091) 35,861 (80,952)

Net (loss) income attributable to Liberty Oilfield Services Inc.

Depreciation, depletion and amortization 262,757 180,084 82,673

Loss (gain) on disposal of assets 779 (411) 1,190

Operating loss (181,224) (177,026) (4,198)

Other (income) expense, net (3,436) 14,505 (17,941)

Net loss before taxes (177,788) (191,531) 13,743

Income tax expense (benefit) 9,216 (30,857) 40,073

Net loss (187,004) (160,674) (26,330)

Net loss attributable to non-controlling interests (7,760) (45,091) 37,331

Net loss attributable to Liberty Oilfield Services Inc.

stockholders $ (179,244) $ (115,583) $ (63,661)

Our revenue decreased $1.0 billion, or 51.5%, to $965.8 million for the year ended December 31, 2020 compared to $2.0 billion for the year ended December 31, 2019.

Average active fleets decreased 42.1% to 13.2 from 22.8 average active fleets deployed during the year ended December 31, 2020 and 2019, respectively, as the Company reduced the staffed fleets in April 2020 in response to market conditions, as discussed in “Recent Trends and Outlook” above.

Further, revenue per average active fleet decreased 16.2% to $73.2 million for the year ended December 31, 2020 compared to $87.3 million for the year ended December 31, 2019, attributable to lower demand for frac services in the market as previously discussed.

Our revenue increased $1.5 billion, or 156%, to $2.5 billion for the year ended December 31, 2021 compared to $1.0 billion for the year ended December 31, 2020.

The increase is attributable to higher fleet utilization and service prices, as well as additional fleets and service lines obtained through the OneStim Acquisition, which drove higher revenue, commensurate with the energy demand recovery.

Cost of Services

Cost of services (excluding depreciation and amortization) decreased $763.2 million, or 47.1%, to $858.0 million for the year ended December 31, 2020 compared to $1.6 billion for the year ended December 31, 2019.

The lower expense was primarily related to the reduced levels of activity from fewer average active fleets deployed during 2020, as described above, and to a lesser extent from cost-cutting measures related to personnel costs enacted during 2020 including reduction in headcount and furloughs, as well as a temporary suspension of bonus and 401(k) match programs.

Cost of services (excluding depreciation and amortization) increased $1.4 billion, or 162%, to $2.2 billion for the year ended December 31, 2021 compared to $0.9 billion for the year ended December 31, 2020.

The higher expense was primarily related to the increase in activity, as discussed above, as well as increases in material, personnel, and repairs and maintenance costs related to global supply chain challenges, inflationary pressures and material prices.

The Company also reinstated bonus programs and the 401(k) match program, both of which we temporarily suspended during 2020.

General and Administrative Expenses

General and administrative expenses decreased by $13.5 million, or 13.8%, to $84.1 million for the year ended December 31, 2020 compared to $97.6 million for the year ended December 31, 2019 primarily related to a decrease in personnel costs, excluding share based compensation, of $15.1 million due to the reduction in headcount, furlough and flexible cost structure, as well as the temporary suspension of bonus and 401(k) match programs.

Partially offsetting this decrease, general and administrative expense included $12.9 million of share based compensation expense during the year ended December 31, 2020 compared to $9.2 million for the year ended December 31, 2019.

General and administrative expenses increased $39.3 million, or 47%, to $123.4 million for the year ended December 31, 2021 compared to $84.1 million for the year ended December 31, 2020 primarily related to an increase in personnel benefits due to additional headcount commensurate with the acquisitions of OneStim and PropX.

The furlough and flexible cost structure implemented in 2020 also ended prior to 2021.

Additionally, during 2021, the Company reinstated bonus programs and the 401(k) match program, both of which we temporarily suspended during 2020.

Transaction, Severance and Other Costs

Transaction costs were $ 8.5 million for the year ended December 31, 2020 compared to $0 for the year ended December 31, 2019.

Such costs were incurred in connection with the OneStim Acquisition and included investment banking, legal, accounting and other professional services provided in connection with closing the transaction.

Severance and other costs were $12.6 million for the year ended December 31, 2020 compared to $0 for the year ended December 31, 2019.

The costs were primarily related to the reduction in our workforce in April 2020 and the commencement of furlough schedules for remaining employees in May 2020 during which the Company continued to pay insurance and other benefits.

Transaction costs were $15.1 million for the year ended December 31, 2021 compared to $8.5 million for the year ended December 31, 2020.

Such costs incurred primarily relate to investment banking, legal, accounting, other professional services provided and integration costs in connection with the acquisitions of OneStim and PropX.

Severance and other costs were $0 during the year ended December 31, 2021 compared to $12.6 million for the year ended December 31, 2020 which were related to one time severance costs and insurance and other benefits for furloughed employees.

The Company did not lay-off or furlough any employees during 2021.

Depreciation and Amortization of Intangible Assets

Depreciation and amortization of intangible assets expense increased $14.7 million, or 8.9%, to $180.1 million for the year ended December 31, 2020 compared to $165.4 million for the year ended December 31, 2019.

The increase in 2020 was due to a full year of depreciation for one fleet deployed during 2019, as well as one additional fleet deployed during early 2020.

(Gain) Loss on Disposal of Assets

(Gain) loss on disposal of assets increased $3.0 million to a gain of $0.4 million for the year ended December 31, 2020 compared to a loss of $2.6 million for the year ended December 31, 2019.

During 2020, we reduced the number of light duty pick-ups in our fleet based on our lower levels of activity and realized gains upon sale commensurate with lease terminations.

Operating (Loss) Income

We realized an operating loss of $177.0 million for the year ended December 31, 2020 compared to operating income of $103.6 million for the year ended December 31, 2019.

The decrease is primarily due to the $1.0 billion, or 51.5%, decrease in total revenue only partially offset by a $743.9 million decrease in total operating expenses, the significant components of which are discussed above.

The decline in operating income was significantly impacted by reduced customer work as a result of the COVID-19 pandemic and steep decline in oil prices in March and April 2020.

Interest Expense, net

The decrease in interest expense, net of $0.2 million, or 1.2%, to $14.5 million during the year ended December 31, 2020 compared to $14.7 million during the year ended December 31, 2019, was due to lower interest expense on credit facilities and from finance leases, largely offset by reduced interest income from excess cash on hand.

Net (Loss) Income Before Taxes

We realized a net loss before taxes of $191.5 million for the year ended December 31, 2020 compared to net income before taxes of $88.9 million for the year ended December 31, 2019.

The decrease is primarily attributable to a decrease in revenue, as discussed above, related to the decrease in pricing and activity.

Income Tax (Benefit) Expense

We recognized a tax benefit of $30.9 million for the year ended December 31, 2020, an effective rate of 16.1 %, compared to expense of $14.1 million for the year ended December 31, 2019, an effective rate of 15.8%.

The decrease in tax expense is primarily attributable to a decrease in revenue, as discussed above, related to the decrease in pricing and activity.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expense increased $82.7 million, or 45.9%, to $262.8 million for the year ended December 31, 2021 compared to $180.1 million for the year ended December 31, 2020.

The increase in 2021 was due to the addition of active fleets and other property from the acquisitions of OneStim and PropX.

Loss (gain) on Disposal of Assets

The Company recorded a loss on disposal of assets of $0.8 million for the year ended December 31, 2021 compared to a gain of $0.4 million for the year ended December 31, 2020.

In an effort to consolidate operations in certain basins after the OneStim Acquisition, the Company sold three real estate properties during the fourth quarter of 2021, which collectively resulted in a small loss on sale, along with regular sales of equipment that was no longer being used.

During 2020, the Company reduced the number of light duty pick-ups used in fleets based on lower levels of activity;

and the Company realized gains upon sale commensurate with lease terminations.

Operating Loss

Operating loss increased $4.2 million, or 2.4%, to $181.2 million for the year ended December 31, 2021 compared to operating loss of $177.0 million for the year ended December 31, 2020.

The increased operating loss is primarily due to the cost of services rising at a slightly higher rate than revenue increases through the rebound in activity levels in 2021.

Other (Income) Expense, net

The Company recorded other income, net of $3.4 million for the year ended December 31, 2021 compared to other expense, net of $14.5 million during the year ended December 31, 2020.

Other (income) expense, net is comprised of gain on remeasurement of liability under the TRAs and interest expense, net.

During the second quarter of 2021, the Company entered into a three-year cumulative pre-tax book loss primarily due to COVID-19 related losses and recognized a valuation allowance on a portion of its deferred tax assets in accordance with ASC 740.

As a result of the recognition of a valuation allowance, the Company also remeasured the liability under the TRAs resulting in a gain of $19.0 million during the year ended December 31, 2021.

Interest expense, net was consistent between periods, increasing $1.1 million as a result of increased borrowings under the credit facility and lower interest income during the year ended December 31, 2021 compared to the year ended December 31, 2020.

Net Loss Before Taxes

Net loss before taxes decreased $13.7 million, or 7.2%, to $177.8 million for the year ended December 31, 2021 compared $191.5 million for the year ended December 31, 2020.

The decrease in loss is primarily due to the gain recognized upon remeasurement of the TRAs during the year ended December 31, 2021 as compared to the year ended December 31, 2020 partially offset by the increase in operating loss discussed above.

Income Tax Expense (Benefit)

Tax expense of $9.2 million was recognized for the year ended December 31, 2021, an effective rate of (5.2)%, compared to an income tax benefit of $30.9 million, at an effective rate of 16.1%, recognized for the year ended December 31, 2020.

The income tax expense is primarily attributable to the full valuation allowance recorded on the net deferred tax assets as of June 30, 2021, and Canada income and provincial taxes.

Comparison of Non-GAAP Financial Measures

We view EBITDA and Adjusted EBITDA as important indicators of performance.

We define EBITDA as net income before interest, income taxes, depreciation and amortization.

We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock based compensation, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, asset impairment charges, bad debt reserves and non-recurring expenses that management does not consider in assessing ongoing performance.

Our Board, management, investors and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them 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) and other items that impact the comparability of financial results from period to period.

We define EBITDA as net income (loss) (the most directly comparable GAAP financial measure) before interest, income taxes, depreciation, depletion and amortization.

We define Adjusted EBITDA as EBITDA adjusted to eliminate the effects of items such as non-cash stock based compensation expense, new fleet or new basin start-up costs, fleet lay-down costs, costs of asset acquisitions, gain or loss on the disposal of assets, bad debt reserves and non-recurring expenses that management does not consider in assessing ongoing performance.

Our board of directors, management, investors, and lenders use EBITDA and Adjusted EBITDA to assess our financial performance because it allows them 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, depletion and amortization) and other items that impact the comparability of financial results from period to period.

We present EBITDA and Adjusted EBITDA because we believe they provide useful information regarding the factors and trends affecting our business in addition to measures calculated under GAAP.

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We believe that the presentation of these non-GAAP financial measures will provide useful information to investors in assessing our financial performance and results of operations.

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

Net income is the GAAP measure most directly comparable to EBITDA and Adjusted EBITDA.

Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure.

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(in thousands)

Net (loss) income $ (160,674) $ 74,864 $ (235,538)

Net loss $ (187,004) $ (160,674) $ (26,330)

Depreciation and amortization 262,757 180,084 82,673

Interest expense, net 15,603 14,505 1,098

Income tax (benefit) expense (30,857) 14,052 (44,909)

Income tax expense (benefit) 9,216 (30,857) 40,073

EBITDA $ 100,572 $ 3,058 $ 97,514

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Fleet start-up and lay-down costs 2,751 12,175 (9,424)

Asset acquisition costs 8,497 — 8,497

(Gain) loss on disposal of assets (411) 2,601 (3,012)

Transaction, severance and other costs 15,138 21,061 (5,923)

Loss (gain) on disposal of assets 779 (411) 1,190

Provision for credit losses 745 4,877 (4,132)

Non-recurring payroll expense 2,398 — 2,398

Severance and related costs 10,166 — 10,166

Gain on remeasurement of liability under tax receivable agreement (19,039) — (19,039)

Adjusted EBITDA $ 120,892 $ 57,899 $ 62,993

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Adjusted EBITDA was $120.9 million for the year ended December 31, 2021 compared to $57.9 million for the year ended December 31, 2020.

The decreases in EBITDA and Adjusted EBITDA resulted from the decreased revenue and other factors described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for Year Ended December 31, 2020, Compared to Year Ended December 31, 2019 .

The increases in EBITDA and Adjusted EBITDA primarily resulted from improved market conditions and increased activity levels as described above under the captions Revenue , Cost of Services, and General and Administrative Expenses for the Year Ended December 31, 2021, Compared to Year Ended December 31, 2020 .

Liquidity and Capital Resources

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We expect to fund operations and organic growth with cash flows from operations and available borrowings under our Credit Facilities.

We may incur additional indebtedness or issue equity in order to fund growth opportunities that we pursue via acquisition, such as with the OneStim Acquisition.

We monitor the availability of capital resources such as equity and debt financings that could be leverage for current or future financial obligations including those related to acquisitions, capital expenditures, working capital and other liquidity requirements.

We may incur additional indebtedness or issue equity in order to meet our capital expenditure activities and liquidity requirements, as well as to fund growth opportunities that we pursue, including via acquisition, such as with the acquisitions of OneStim and PropX.

Our primary uses of capital have been capital expenditures to support organic growth and funding ongoing operations, including maintenance and fleet upgrades.

Cash and cash equivalent s decreased by $43.7 million to $69.0 million as of December 31, 2020 compared to $112.7 million as of December 31, 2019.

We believe that cash on hand, our operating cash flows and available borrowings under our Credit Facilities will be sufficient to fund our operations for at least the next twelve months.

Cash and cash equivalent s decreased by $49.0 million to $20.0 million as of December 31, 2021 compared to $69.0 million as of December 31, 2020, while working capital excluding cash and current liabilities under debt and lease arrangements decreased $104.5 million.

We have $350.0 million committed under the ABL Facility (net of any outstanding letters of credit), subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory (with the ability to request an increase in the size of the ABL Facility by $75 million) available to finance working capital needs.

As of December 31, 2021, the borrowing base was calculated to be $269.0 million, and the Company had $18.0 million outstanding in addition to a letter of credit in the amount of $1.5 million, with $249.5 million of remaining availability.

Additionally, we have $106.5 million borrowings remaining on the Term Loan Facility, which was originally $175.0 million.

On October 22, 2021, the Company entered into an amendment to the ABL Facility (the “Revolving Credit Agreement Amendment”).

The Revolving Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement originally entered into by the parties on September 19, 2017, which governs the Company’s ABL Facility.

Along with other revisions, the Revolving Credit Agreement Amendment (i) expanded the definition of borrowing base to include certain eligible US investment grade accounts, Canadian accounts solely after a specified event, and both chemical and spare parts inventory;

(ii) increased the maximum revolver amount from $250.0 million to $350.0 million (with the ability to request an increase in the size of the ABL Facility by $75 million);

(iii) increased certain indebtedness baskets;

(iv) provided additional flexibility for a potential future internal structuring;

(v) added new lenders to the facility;

and (vi) extended the maturity date to the earlier of (a) October 22, 2026 and (b) to the extent the debt under the Term Loan Facility remains outstanding 90 days prior to the final maturity of the Term Loan Facility.

The ABL Facility was initially scheduled to mature on the earlier to occur of (i) September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility.

On October 22, 2021, the Company entered into a Fifth Amendment to Credit Agreement, Second Amendment to Guaranty and Security Agreement and Termination of Right of First Offer Letter.

The Term Loan Credit Agreement Amendment further amends the credit agreement and guaranty and security agreement and terminates the Right of First Offer Letter originally entered into by the parties on September 19, 2017, which governs the Company’s Term Loan Facility.

Along with other revisions, the Term Loan Credit Agreement Amendment (i) increased certain indebtedness baskets;

(ii) provided additional flexibility for a potential future internal structuring;

(iii) extended the maturity date through September 19, 2024;

and (iv) terminated a right of first offer in favor of the Term Loan Facility lenders.

The Term Loan Facility was initially scheduled to mature on September 19, 2022.

The Credit Facilities contain covenants that restrict our ability to take certain actions.

At December 31, 2021, we were in compliance with all debt covenants.

See Note 8 —Debt to the consolidated financial statements included in “Item 8.

Financial Statements and Supplementary Data” for further details.

The following table summarizes our cash flows for the periods indicated:

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Net cash used in investing activities (186,494) (100,269) (86,225)

Net cash used in financing activities (28,868) (57,375) 28,507

Net increase in cash and cash equivalents $ (43,712) $ 9,378 $ (53,090)

Net cash provided by (used in) financing activities 2,056 (28,868) 30,924

Analysis of Cash Flow Changes Between the Years Ended December 31, 2021 and December 31, 2020

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Net cash provided by operating activities was $135.5 million for the year ended December 31, 2021, compared to net cash provided by operating activities of $85.4 million for the year ended December 31, 2020.

The $175.7 million decrease in cash from operating activities was primarily attributable to a $1.0 billion decrease in revenues, offset by a $743.9 million decrease in operating expenses and a $63.3 million increase in cash from changes in working capital for the year ended December 31, 2020, compared to a $21.6 million decrease in cash from changes in working capital for the year ended December 31, 2019.

The $50.0 million increase in cash from operating activities was primarily attributable to a $1.5 billion increase in revenues, offset by a $1.4 billion increase in cash operating expenses and a $46.9 million increase in cash from changes in working capital for the year ended December 31, 2021, compared to a $63.3 million increase in cash from changes in working capital for the year ended December 31, 2020.

Investing Activities .

Net cash used in investing activities was $186.5 million for the year ended December 31, 2021, compared to $100.3 million for the year ended December 31, 2020.

The $94.1 million decrease in net cash used in investing activities is attributable to a decrease in capital expenditures in an effort to reduce spending and as a result of the lower fleet count in 2020.

The $86.2 million increase in cash used in investment activities related to a decrease in spend in 2020 starting in the second quarter and remaining throughout the year due to the COVID-19 pandemic.

Investing increased during 2021 when the markets recovered to pre-pandemic levels and $11.9 million was used in the fourth quarter for the PropX Acquisition.

Financing Activities .

Net cash used in financing activities was $28.9 million for the year ended December 31, 2020, compared to $57.4 million for the year ended December 31, 2019.

The $28.5 million decrease in cash used in financing activities was primarily due to an $18.4 million decrease in share repurchases and a $16.6 million reduction in dividends and per unit distributions to non-controlling interest unitholders as a result of the suspension of the dividend in April 2020.

Partially offsetting the decreases was a $6.8 million increase in cash used in financing activities as a result of payments made to non-controlling interest unitholders under the TRAs as a result of the 2020 refund of a portion of cash taxes paid in 2018.

Debt Agreements

On September 19, 2017, the Company entered into two new credit agreements for a revolving line of credit up to $250.0 million (the “ABL Facility”) and a $175.0 million term loan (the “Term Loan Facility”, and together with the ABL Facility the “Credit Facilities”).

Following is a description of the ABL Facility and the Term Loan Facility.

Under the terms of the ABL Facility, up to $250.0 million may be borrowed, subject to certain borrowing base limitations based on a percentage of eligible accounts receivable and inventory.

On May 29, 2020 the Company amended the ABL Facility to allow accounts receivables that are more than 90 but less than 120 days past their original invoice date to be included in the determination of eligible accounts receivables, up to a limit of $ 37.5 million when combined with receivable that are more than 60 but less than 90 days past their due date to be included in the borrowing base.

The expanded borrowing base terms were in effect from May 1, 2020 through December 31, 2020.

As of December 31, 2020, the borrowing base was calculated to be $115.1 million, and the Company had no borrowings outstanding, except for a letter of credit in the amount of $0.8 million, with $114.3 million of remaining availability.

Borrowings under the ABL Facility bear interest at the London InterBank Offered Rate (“LIBOR”) or a base rate, plus an applicable LIBOR margin of 1.5% to 2.0% or base rate margin of 0.5% to 1.0%, as defined in the ABL Facility credit agreement.

The unused commitment is subject to an unused commitment fee of 0.375% to 0.5%.

Interest and fees are payable in arrears at the end of each month, or, in the case of LIBOR loans, at the end of each interest period.

The ABL Facility matures on the earlier of (i) September 19, 2022 and (ii) to the extent the debt under the Term Loan Facility remains outstanding, 90 days prior to the final maturity of the Term Loan Facility, which matures on September 19, 2022.

Borrowings under the ABL Facility are collateralized by accounts receivable and inventory, and further secured by the Company, Liberty LLC and R/C IV Non-U.S.

LOS Corp., a Delaware corporation (“R/C IV”) and a subsidiary of the Company, as parent guarantors.

Term Loan Facility

The Term Loan Facility provides for a $175.0 million term loan, of which $108.2 million remained outstanding as of December 31, 2020.

Amounts outstanding bear interest at LIBOR or a base rate, plus an applicable margin of 7.625% or 6.625%, respectively, and the weighted average rate on borrowings was 8.6% as of December 31, 2020.

The Company is required to make quarterly principal payments of 1% per annum of the initial principal balance, commencing on December 31, 2017, with final payment due at maturity on September 19, 2022.

The Term Loan Facility is collateralized by the fixed assets of LOS and its subsidiaries, and is further secured by the Company, Liberty LLC and R/C IV, as parent guarantors.

The Credit Facilities include certain non-financial covenants, including but not limited to restrictions on incurring additional debt and certain distributions.

Moreover, the ability of the Company to incur additional debt and to make distributions is dependent on maintaining a maximum leverage ratio.

The Term Loan Facility requires mandatory prepayments upon certain dispositions of property or issuance of other indebtedness, as defined, and annually a percentage of excess cash flow (25% to 50%, depending on leverage ratio, of consolidated net income less capital expenditures and other permitted payments, commencing with the year ending December 31, 2018).

Certain mandatory prepayments and optional prepayments are subject to a prepayment premium of 3% of the prepaid principal declining annually to 1% during the first three years of the term of the Term Loan Facility.

The Credit Facilities are not subject to financial covenants unless liquidity, as defined in the respective credit agreements, drops below a specified level.

Under the ABL Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined in the credit agreement governing the ABL Facility, of 1.0 to 1.0 for each period if excess availability is less than 10% of the borrowing base or $12.5 million, whichever is greater.

Under the Term Loan Facility, the Company is required to maintain a minimum fixed charge coverage ratio, as defined, of 1.2 to 1.0 for each trailing twelve-month period if the Company’s liquidity, as defined, is less than $25.0 million for at least five consecutive business days.

The Company was in compliance with these covenants as of December 31, 2020.

Contractual Obligations

The table below provides estimates of the timing of future payments that we are contractually obligated to make based on agreements in place at December 31, 2020.

Payments Due by Period

($ in thousands)

Total Less than 1

year 1 – 3 years 4 – 5 years More than 5 years

ABL Facility(1) $ — $ — $ — $ — $ —

Term Loan Facility(1) 108,215 1,750 106,465 — —

Estimated interest payments(2) 16,062 9,406 6,656 — —

Operating lease obligations(3) 85,628 26,546 27,197 9,905 21,980

Finance lease obligations(4) 33,731 21,270 12,461 — —

Purchase commitments(5) 127,420 82,141 27,347 17,932 —

Obligations under the TRAs(6) 56,594 — 25,841 9,293 21,460

Total $ 427,650 $ 141,113 $ 205,967 $ 37,130 $ 43,440

(1) Payments on our ABL Facility and Term Loan Facility exclude interest payments.

Payments are based on debt balances as of December 31, 2020.

(2) Estimated interest payments are based on debt balances as of December 31, 2020.

Interest rates applied are based on the weighted average rate as of December 31, 2020.

(3) Operating lease obligations include payments for leased facilities, equipment and vehicles.

(4) Finance lease obligations include payments for leased vehicles.

(5) Purchase commitments represent payments under supply agreements for the purchase and transportation of proppants.

Some of the agreements include minimum monthly purchase commitments, including agreements under which a shortfall fee may be applied.

The shortfall fee may be offset by purchases in excess of the minimum requirement during future periods, as allowed for by each agreement.

(6) The timing and amount(s) of the aggregate payments due under the TRAs may vary based on a number of factors, including the timing and amount of the taxable income we generate each year and the tax rate then applicable.

Net cash provided by financing activities was $2.1 million for the year ended December 31, 2021, compared to net cash used in financing activities of $28.9 million for the year ended December 31, 2020.

The $30.9 million change in financing activities was primarily due to net borrowings of $18.0 million on the ABL Facility during the year ended December 31, 2021, compared to no borrowings on the ABL Facility for the year ended December 31, 2020.

Additionally, there was a $5.8 million decrease in dividends and per unit distributions to non-controlling interest unitholders as a result of the suspension of the dividend in April 2020.

Other distributions and advance payments to non-controlling interest unitholders was a net receipt of $1.4 million during the year ended December 31, 2021, compared to net payment of $6.8 million during the year ended December 31, 2020 due to a decrease in payments made under the TRAs.

These decreases were offset by a $2.6 million increase in payments made for tax withholding on restricted stock unit vesting as a larger number of units vested at a higher stock price in 2021 compared to 2020.

Cash Requirements

Our material cash commitments consists primarily of obligations under long-term debt, TRAs, finance and operating leases for property and equipment, and purchase obligations as part of normal operations.

Certain amounts included in our contractual obligations as of December 31, 2021 are based on our estimates and assumptions about these obligations, including pricing, volumes and duration.

We have no material off balance sheet arrangements as of December 31, 2021, except for purchase commitments under supply agreements disclosed below.

See Note 8 —Debt to the consolidated financial statements included in “Item 8.

Financial Statements and Supplementary Data” for information regarding scheduled maturities of our long-term debt.

See Note 6 —Leases to the consolidated financial statements included in “Item 8.

Financial Statements and Supplementary Data” for information regarding scheduled maturities of finance and operating leases.

As of December 31, 2021, we had expected cash payments for estimated interest on our long-term debt and finance lease obligations of $10.6 million payable within the next twelve months and $17.4 million payable thereafter.

As of December 31, 2021, we had purchase obligations of $24.6 million payable within the next twelve months and $1.4 million payable thereafter.

See Note 15 —Commitments & Contingencies to the consolidated financial statements included in “Item 8.

Financial Statements and Supplementary Data” for information regarding scheduled contractual obligations.

We currently do not expect to make any payments under the TRAs within the next twelve months, future amounts payable under the TRAs are dependent upon future events.

See Note 12 —Income Taxes to the consolidated financial statements included in “Item 8.

Financial Statements and Supplementary Data” for information regarding the TRAs.

Other Factors Affecting Liquidity

Customer receivables:

In line with industry practice, we typically bill our customers for services provided in arrears dependent upon contractual terms.

In weak economic environments, we may experience delays in collection from our customers.

Due to the impact of the COVID-19 pandemic on the industry, we have experienced delays in customer payments and agreed to extended payment terms, however, we have not experienced any material non-payment events.

Tax Receivable Agreements

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There can be no assurance that we will be able to finance our obligations under the TRAs.

Following the IPO, the Company is a corporation and is subject to U.S.

The Company is a corporation and is subject to U.S.

federal, state and local income tax on its share of Liberty LLC’s taxable income.

As a result of the IPO and Corporate Reorganization, the Company recorded deferred tax assets and liabilities for the difference between the book value of assets and liabilities for financial reporting purposes and those amounts applicable for income tax purposes.

The effective combined U.S.

federal and state income tax rate applicable to the Company for the year ended December 31, 2020 and 2019 was 16.1% and 15.8%, respectively.

The Company’s effective tax rate is significantly less than the federal statutory income tax rate of 21.0% primarily because no taxes are payable by the Company for the non-controlling interest’s share of Liberty LLC’s pass-through income for federal, state and local income tax reporting.

The Company recognized income tax benefit of $30.9 million and income tax expense of $14.1 million for the years ended December 31, 2020 and 2019, respectively.

The Company is also subject to Canada federal and provincial income taxes on its foreign operations.

The combined effective tax rate applicable to the Company for the year ended December 31, 2021 and 2020 was (5.2)% and 16.1%, respectively.

The Company’s effective tax rate is significantly less than the federal statutory income tax rate of 21.0% due to the Company recording a valuation allowance on its U.S.

net deferred tax assets as of December 31, 2021, due to entering into a three year cumulative pre-tax book loss position, primarily as a result of COVID-19 related losses in 2021.

The Company’s effective tax rate is also less than the statutory rate because of foreign operations for 2021, and the non-controlling interest’s share of Liberty LLC’s pass-through results for federal, state and local income tax reporting, upon which no taxes are payable by the Company for the years ended December 31, 2021 and 2020.

The Company recognized income tax expense of $9.2 million and an income tax benefit of $30.9 million for the years ended December 31, 2021 and 2020, respectively.

Per the Coronavirus Aid, Relief and Economic Security (“CARES”) Act enacted on March 27, 2020, net operating losses (“NOL”) incurred in 2018, 2019, and 2020 may be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes.

The Company has previously applied for and expects to receive a NOL carryback refund to recover $5.5 million of cash taxes paid by the Company in 2018.

This amount has been reflected as a receivable in the prepaids and other current assets line item in the accompanying audited consolidated balance sheets.

Refer to Note 12— Income Taxes to the consolidated financial statements for additional information related to income tax expense.

Critical Accounting Policies and Estimates

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We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.

We believe the following are the critical accounting policies used in the preparation of our combined financial statements, as well as the significant estimates and judgments affecting the application of these policies.

This discussion and analysis should be read in conjunction with our combined financial statements and related notes included in “Item 8.

We believe the following are the critical accounting policies used in the preparation of our consolidated financial statements, as well as the significant estimates and judgments affecting the application of these policies.

This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in “Item 8.

Financial Statements and Supplementary Data.

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The purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values.

Fair value of the acquired assets and liabilities is measured

in accordance with the guidance of ASC 850 - Fair Value Measurements, using discounted cash flows and other applicable valuation techniques.

Fair value of the acquired assets and liabilities is measured in accordance with the guidance of ASC 850 - Fair Value Measurements, using discounted cash flows and other applicable valuation techniques.

Any acquisitions related costs incurred by the Company are expensed as incurred.

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When alternative courses of action to recover the carrying amount of the asset group are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence, which require us to apply judgment.

If the carrying amount of the asset is not recoverable based on its estimated undiscounted cash flows expected to result from the use and eventual disposition, an impairment loss is recognized in an amount by which its carrying amount exceeds its estimated fair value.

exceeds its estimated fair value.

The inputs used to determine such fair value are primarily based upon internally developed cash flow models.

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

Foreign Currency Translation:

Effective January 1, 2021, the Company commenced operations in Canada and therefore added a critical accounting policy for foreign currency translation.

See Note 2―Significant Accounting Policies in the accompanying audited consolidated financial statements included herein and incorporated by reference into this offering memorandum.

Recent Accounting Pronouncements

See Note 2—Significant Accounting Policies— Recently Issued Accounting Standards to the consolidated and combined financial statements included in “Item 8.

See Note 2—Significant Accounting Policies— Recently Issued Accounting Standards to the consolidated financial statements included in “Item 8.

Financial Statements and Supplementary Data” for a discussion of recent accounting pronouncements.

Off Balance Sheet Arrangements

We have no material off balance sheet arrangements as of December 31, 2020, except for purchase commitments under supply agreements as disclosed above under “—Contractual Obligations.” As such, we are not materially exposed to any other financing, liquidity, market or credit risk that could arise if we had engaged in such financing arrangements.

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