Item 7. Management’s Discussion and Analysis
Item 7. 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 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 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.
Overview
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.
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; (ii) our Liberty Quiet Fleet® design which significantly reduces noise levels compared to conventional hydraulic fracturing fleets; (iii) hydraulic fracturing fluid systems tailored to the specific reservoir properties in the basins in which we operate; (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.
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Recent Trends and Outlook
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
Over the past decade, E&P companies have focused on exploiting the vast resource potential available across many of North America’s unconventional resource plays through the application of horizontal drilling and completion technologies, including the use of multi-stage hydraulic fracturing, in order to increase recovery of oil and natural gas. 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 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.
Improved drilling economics from horizontal drilling and greater rig efficiencies . Unconventional resources are increasingly being targeted through the use of horizontal drilling. 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. North American drilling rigs have incorporated newer technologies, which allow them to drill rock more effectively and quickly, meaning each rig can drill more wells in a given period. These include improved drilling technologies and the incorporation of geosteering techniques which allow better placement of the wellbore. Drilling rigs have also incorporated new technology which allows fully-assembled rigs to automatically “walk” from one location to the next without disassembling and reassembling the rig, greatly reducing the time it takes to move from one drilling location to the next. 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 Lium Research, has dropped from 28 days in 2014 to 17 days in 2021.
Increased complexity and service intensity of horizontal well completions . In addition to improved rig efficiencies discussed above, E&P companies are also improving the subsurface techniques and technologies used to exploit unconventional resources. These improvements have targeted increasing the exposure of each wellbore to the reservoir by drilling longer horizontal lateral sections of the wellbore. 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 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
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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 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. Utilizing a larger frac fleet (1.25x to 2x the normal horsepower), operators are fracturing stages in two separate wells on a pad simultaneously as a single operation. When compared to typical zipper-frac operations, this new method allows for more lateral feet to be completed in a day. 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 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.
How We Generate Revenue
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 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. The majority of our services are priced based on prevailing market conditions and changing input costs at the time the services are provided, giving consideration to the specific requirements of the customer.
Our hydraulic fracturing and wireline services are performed in sections, which we refer to as fracturing stages. 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. 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.
Costs of Conducting Our Business
The principal expenses involved in conducting our business are direct cost of personnel, services and materials used in the provision of services, general and administrative expenses, and depreciation and amortization. A large portion of the costs we incur in our business are variable based on the number of hydraulic fracturing jobs and the requirements of services provided to our customers. We manage the level of our fixed costs, except depreciation and amortization, based on several factors, including industry conditions and expected demand for our services.
How We Evaluate Our Operations
We use a variety of qualitative, operational and financial metrics to assess our performance. First and foremost of these is a qualitative assessment of customer satisfaction because ensuring we are a valuable partner to our customers is the key to achieving our quantitative business metrics. Among other measures, management considers each of the following:
• Revenue;
• Operating Income;
• EBITDA;
• Adjusted EBITDA;
• Net Income Before Taxes; and
• Earnings per Share.
Revenue
We analyze our revenue by comparing actual monthly revenue to our internal projections for a given period and to prior periods to assess our performance. We also assess our revenue in relation to the number of fleets we have deployed (revenue per average active fleet) from period to period.
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Operating Income
We analyze our operating income, which we define as revenues less direct operating expenses, depreciation and amortization and general and administrative expenses, to measure our financial performance. We believe operating income is a meaningful metric because it provides insight on profitability and true operating performance based on the historical cost basis of our assets. We also compare operating income to our internal projections for a given period and to prior periods.
EBITDA and Adjusted EBITDA
We view EBITDA and Adjusted EBITDA as important indicators of performance. We define EBITDA as net income (loss) 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 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. 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
Year Ended December 31, 2021, Compared to Year Ended December 31, 2020
Years Ended December 31,
Description 2021 2020 Change
(in thousands)
Revenue $ 2,470,782 $ 965,787 $ 1,504,995
Cost of services, excluding depreciation and amortization shown separately 2,249,926 857,981 1,391,945
General and administrative 123,406 84,098 39,308
Transaction, severance and other costs 15,138 21,061 (5,923)
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)
Less: 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)
Revenue
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) 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 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.
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Transaction, Severance and Other Costs
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, 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 (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.
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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.
Note Regarding Non-GAAP Financial Measures
EBITDA and Adjusted EBITDA are not financial measures presented in accordance with GAAP. 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 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. Each of these non-GAAP financial measures has important limitations as an analytical tool due to exclusion of some but not all items that affect the most directly comparable GAAP financial measures. You should not consider EBITDA or Adjusted EBITDA in isolation or as substitutes for an analysis of our results as reported under GAAP. Because EBITDA and Adjusted EBITDA 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.
The following tables present a reconciliation of EBITDA and Adjusted EBITDA to our net income, which is the most directly comparable GAAP measure for the periods presented:
Year Ended December 31, 2021 Compared to Year Ended December 31, 2020: EBITDA and Adjusted EBITDA
Years Ended December 31,
Description 2021 2020 Change
(in thousands)
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 expense (benefit) 9,216 (30,857) 40,073
EBITDA $ 100,572 $ 3,058 $ 97,514
Stock based compensation expense 19,946 17,139 2,807
Fleet start-up and lay-down costs 2,751 12,175 (9,424)
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)
Gain on remeasurement of liability under tax receivable agreement (19,039) — (19,039)
Adjusted EBITDA $ 120,892 $ 57,899 $ 62,993
EBITDA was $100.6 million for the year ended December 31, 2021 compared to $3.1 million for the year ended December 31, 2020. 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 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
Overview
Historically, our primary sources of liquidity to date have been cash flows from operations, proceeds from our IPO, and borrowings under our Credit Facilities. We expect to fund operations and organic growth with cash flows from operations and available borrowings under our Credit Facilities. 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.
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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.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
Years Ended December 31,
Description 2021 2020 Change
(in thousands)
Net cash provided by operating activities $ 135,467 $ 85,425 $ 50,042
Net cash used in investing activities (186,494) (100,269) (86,225)
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
Operating Activities . 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 $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.
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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 $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 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.
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Tax Receivable Agreements
In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax (computed using simplifying assumptions to address the impact of state and local taxes) that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the IPO as a result, as applicable to each of the TRA Holders, of (i) certain increases in tax basis that occur as a result of the Company’s acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holders’ Liberty LLC Units in connection with the IPO or pursuant to the exercise of the right of each Liberty Unit Holder (the “Redemption Right”), subject to certain limitations, to cause Liberty LLC to acquire all or a portion of its Liberty LLC Units for, at Liberty LLC’s election, (A) shares of our Class A Common Stock at the specific redemption ratio or (B) an equivalent amount of cash, or, upon the exercise of the Redemption Right, the right of the Company (instead of Liberty LLC) to, for administrative convenience, acquire each tendered Liberty LLC Unit directly from the redeeming Liberty Unit Holder (the “Call Right”) for, at its election, (1) one share of Class A Common Stock or (2) an equivalent amount of cash, (ii) any net operating losses available to the Company as a result of the Corporate Reorganization, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, any payments the Company makes under the TRAs.
With respect to obligations the Company expects to incur under the TRAs (except in cases where the Company elects to terminate the TRAs early, the TRAs are terminated early due to certain mergers, asset sales, or other changes of control or the Company has available cash but fails to make payments when due), generally the Company may elect to defer payments due under the TRAs if the Company does not have available cash to satisfy its payment obligations under the TRAs or if its contractual obligations limit its ability to make such payments. Any such deferred payments under the TRAs generally will accrue interest. In certain cases, payments under the TRAs may be accelerated and/or significantly exceed the actual benefits, if any, the Company realizes in respect of the tax attributes subject to the TRAs. The Company accounts for amounts payable under the TRAs in accordance with Accounting Standard Codification (“ASC”) Topic 450, Contingencies (“ASC Topic 450”).
If the Company experiences a change of control (as defined under the TRAs) or the TRAs otherwise terminate early, the Company’s obligations under the TRAs could have a substantial negative impact on its liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. There can be no assurance that we will be able to finance our obligations under the TRAs.
Income Taxes
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. 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
The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations.
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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 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. ”
Business Combinations : Business combinations are accounted for using the acquisition method of accounting in accordance with the ASC Topic 805 - Business Combinations, as amended by Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805), Clarifying the Definition of a Business. 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. Any acquisitions related costs incurred by the Company are expensed as incurred. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill if the definition of a business is met. Operating results of an acquired business are included in our results of operations from the date of acquisition.
Revenue Recognition: Revenue from hydraulic fracturing services is recognized as specific services are provided in accordance with contractual arrangements. If our assessment of performance under a particular contract changes, our revenue and / or costs under that contract may change. In connection with ASC Topic 842 - Leases (“Topic 842”), the Company determined that certain of its service revenue contracts contain a lease component. The Company elected to adopt a practical expedient available to lessors, which allows the Company to combine the lease and service component for certain of the Company’s service contracts when the service component is the predominant component and continues to account for the combined component under ASC Topic 606 - Revenue from Contracts with Customers .
Accounts Receivable: On January 1, 2020, the Company adopted ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) : Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which changes the impairment model for most financial assets and certain other instruments. Specifically, this new guidance requires using a forward looking, expected loss model for trade and other receivables, held-to-maturity debt securities, loans, and other instruments. Under ASU 2016-13, a company recognizes as an allowance, the estimate of lifetime expected credit losses, which is expected to result in more timely recognition of such losses.
The Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and an additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. The Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. It is reasonably possible that our estimates of the allowance for doubtful accounts will change and that losses ultimately incurred could differ materially from the amounts estimated in determining the allowance.
Inventory: Inventory consists of raw materials used in the hydraulic fracturing process, such as proppants, chemicals and field service equipment maintenance parts, and is stated at the lower of cost or net realizable value, determined using the weighted average cost method. Net realizable value is determined based on our estimates of selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal, and transportation, each of which require us to apply judgment.
Property and Equipment: We calculate depreciation and amortization on our assets based on the estimated useful lives and estimated salvage values that we believe are reasonable. The estimated useful lives and salvage values are subject to key assumptions such as maintenance, utilization and job variation. These estimates may change due to a number of factors such as changes in operating conditions or advances in technology.
We incur maintenance costs on our major equipment. The determination of whether an expenditure should be capitalized or expensed requires management judgment in the application of how the costs benefit future periods, relative to our capitalization policy. Costs that either establish or increase the efficiency, productivity, functionality or life of a fixed asset are capitalized and depreciated over the remaining useful life of the asset.
Impairment of long-lived and other intangible assets: Long-lived assets, such as property and equipment, right-of-use lease assets and intangible assets, are evaluated for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. Recoverability is assessed using undiscounted future net cash flows of assets grouped at the lowest level for which there are identifiable cash flows independent of the cash flows of other groups of assets. 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
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exceeds its estimated fair value. The inputs used to determine such fair value are primarily based upon internally developed cash flow models. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.
During the year ended December 31, 2020, as a result of negative market indicators including the COVID-19 pandemic, the increased supply of low-priced oil, and customer cancellations, the Company concluded these triggering events could indicate possible impairment of property and equipment. The Company performed a quantitative and qualitative impairment analysis and determined that no impairment had occurred as of March 31, 2020. As of December 31, 2020, the Company concluded that no additional triggering events occurred and the conclusion reached at March 31, 2020 is still appropriate. Such analysis required management to make estimates and assumptions based on historical data and consideration of future market conditions. Given the uncertainty inherent in any projection, heightened by the possibility of unforeseen additional effects of COVID-19, actual results may differ from the estimates and assumptions used, or conditions may change, which could result in impairment charges in the future.
No impairment was recognized during the years ended December 31, 2021, 2020 and 2019.
Leases: The Company adopted Accounting Standards Update (“ASU”) No. 2016-02, Leases ASC Topic 842 effective January 1, 2019. We elected the modified retrospective transition method under ASC Topic 842 and as such information prior to January 1, 2019 has not been restated and continues to be reported under the accounting standards in effect for the period ( ASC Topic 840-Leases ). We carried forward the historical lease classifications and assessment of initial direct costs, account for lease and non-lease components as a single component, and exclude leases with an initial term of less than 12 months in the lease assets and liabilities. For leases entered into after January 1, 2019, the Company determines if an arrangement is a lease at inception and evaluates identified leases for operating or finance lease treatment. Operating or finance lease right-of-use assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. Lease terms may include options to renew; however, we typically cannot determine our intent to renew a lease with reasonable certainty at inception.
Tax Receivable Agreements: In connection with the IPO, on January 17, 2018, the Company entered into two TRAs with the TRA Holders. The TRAs generally provide for the payment by the Company of 85% of the net cash savings, if any, in U.S. federal, state, and local income tax and franchise tax that the Company actually realizes in periods after the IPO as a result of certain tax attributes applicable to each TRA Holder. The Company accounts for amounts payable under the TRAs in accordance with ASC Topic 450, Contingencies .
Share Repurchases: The Company accounts for the purchase price of repurchased Class A Common Stock in excess of par value ($0.01 per share of Class A 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 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 financial statements included in “Item 8. Financial Statements and Supplementary Data” for a discussion of recent accounting pronouncements.
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