Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business and related financing, includes forward‑looking statements that involve risks and uncertainties. You should read the “Risk Factors” section of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward‑looking statements contained in the following discussion and analysis.
Basis of Presentation
This discussion of our results of operations omits our results of operations for the year ended December 31, 2018 and the comparison of our results of operations for the years ended December 31, 2019 and 2018, which may be found in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on June 22, 2020.
Unless otherwise indicated, references in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” to “ProPetro Holding Corp.,” “the Company,” “we,” “our,” “us” or like terms refer to ProPetro Holding Corp. and its subsidiary.
Overview
Our Business
We are a Midland, Texas‑based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production, or E&P, of North American unconventional oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region’s most active and well‑capitalized E&P companies. The Permian Basin is widely regarded as one of the most prolific oil‑producing areas in the United States, and we believe we are one of the leading providers of hydraulic fracturing services in the region by hydraulic horsepower.
Changes to our customers’ well design, shale formations, operating conditions and new technology have resulted in continuous changes to the number of pumps that constitute a fleet. As a result of the asymmetric nature of the number of pumps that constitute a fleet across our customer base and competitors, which we believe will continue to evolve, we view HHP to be an appropriate metric to measure our available hydraulic fracturing capacity. On average, one conventional Tier II hydraulic fracturing fleet consists of approximately 50,000 HHP, depending on job design and customer demand.
Our total available HHP at December 31, 2020 was 1,373,000 HHP (excluding approximately 150,000 HHP we are in the process of permanently retiring), which was comprised of 1,265,000 HHP of conventional Tier II equipment and 108,000 HHP of our new DuraStim® hydraulic fracturing equipment. In addition, we have committed to purchase 50,000 HHP of Tier IV Dynamic Gas Blending (“DGB”) equipment and it is expected to be delivered during the first half of 2021. With the industry transition to lower emission equipment and changes to the number of pumps or HHP that constitute a fleet, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and back up HHP at the wellsites based on our customers’ and operational needs or as we retire and replace conventional Tier II equipment. In light of the energy industry transition to lower emissions equipment, the Company made a strategic decision to permanently retire approximately 150,000 HHP of its existing conventional Tier II pressure pumping equipment . As a result of the Company’s plan to retire 150,000 HHP during the year ended December 31, 2020, we recorded an impairment expense of approximately $21.3 million.
Our DuraStim® hydraulic fracturing equipment is still being tested and to date has only been deployed to our customers’ wellsites on a limited scale. The Company has set a goal to commercialize its first DuraStim® hydraulic
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fracturing equipment to our customer wellsites in the second half of 2021. We also have an option to purchase up to an additional 108,000 HHP of DuraStim® hydraulic fracturing equipment in the future through July 31, 2022. The DuraStim® equipment is powered by electricity. We currently have gas turbines to provide electrical power to our DuraStim® fleet. The electrical power sources for future DuraStim® fleets are still being evaluated and could be supplied by the Company, customers or a third-party supplier.
Pioneer Pressure Pumping Acquisition
On December 31, 2018, we consummated the purchase of pressure pumping and related assets of Pioneer and Pioneer Pumping Services, LLC in the Pioneer Pressure Pumping Acquisition. The pressure pumping assets acquired included hydraulic fracturing pumps of 510,000 HHP, four coiled tubing units and the associated equipment maintenance facility. In connection with the acquisition, we became a long-term service provider to Pioneer under the Pioneer Services Agreement, providing pressure pumping and related services for a term of up to 10 years; provided, that Pioneer has the right to terminate the Pioneer Services Agreement, in whole or part, effective as of December 31 of each of the calendar years of 2022, 2024 and 2026. Pioneer can increase the number of committed fleets prior to December 31, 2022. Pursuant to the Pioneer Services Agreement, the Company is entitled to receive compensation if Pioneer were to idle committed fleets (“idle fees”); however, we are first required to use all economically reasonable effort to deploy the idled fleets to another customer. At the present, we have eight fleets committed to Pioneer. During times when there is a significant reduction in overall demand for our services, the idle fees could represent a material portion of our revenues.
While management believes our relationship with Pioneer will continue beyond December 31, 2022, if Pioneer elects to terminate the Pioneer Services Agreement effective December 31, 2022, or seeks to renegotiate the terms on which we provide services to Pioneer, it could have a material adverse effect on our financial condition, results of operations and cash flows.
Commodity Price and Other Economic Conditions
The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other activity restrictions in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in early March 2020 as a direct result of failed negotiations between OPEC and Russia.
As the breadth of the COVID-19 health crisis expanded throughout the month of March 2020 and governmental authorities implemented more restrictive measures to limit person-to-person contact, global economic activity continued to decline commensurately. The associated impact on the energy industry has been adverse and continued to be exacerbated by the depressed demand in the energy sector and uncertainty in global production levels. In response to the global economic slowdown and depressed demand in the oil and gas industry, OPEC+ has made adjustments to production levels with the objective of rebalancing the energy market. After the March 2020 failed negotiations, OPEC+ subsequently agreed to cut production by 7.7 million BOPD. In January 2021, OPEC+ reconvened to discuss the matter of production cuts in light of unprecedented disruption and supply and demand imbalances. Agreements were reached to gradually increase production by 0.5 million BOPD, starting in January 2021, and adjusting the production reduction from 7.7 million BOPD to 7.2 million BOPD. OPEC+ members have shown compliance with previously agreed upon production levels, and we have seen recovery in crude oil prices from its low point in 2020.
The combined effect of COVID-19 and the energy industry disruptions led to a decline in WTI crude oil prices of approximately 67 percent from the beginning of January 2020, when prices were approximately $62 per barrel, through the end of March 2020, when they were just above $20 per barrel. Overall, with OPEC+ managing production levels and with the development and distribution of COVID-19 vaccines, there has been a gradual recovery in crude oil prices from the low point in March 2020. However, with the uncertainty in the global market resulting from the COVID-19 pandemic, the risk that currently developed vaccines may not be successful in preventing the COVID-19 virus or the outbreak of a new virus, the global demand for crude oil could continue to
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be depressed and crude oil prices could decline. As of March 3, 2021, the WTI price for a barrel of crude oil was approximately $62.
In light of the COVID-19 pandemic and the energy industry disruptions, the Permian Basin rig count decreased significantly from approximately 403 at the beginning of January 2020 to approximately 175 at the end of December 2020, according to Baker Hughes. However, the rig count slowly increased exiting 2020 from its August low of 117 rigs. If the rig count and market conditions do not continue to improve or worsen, the Company expects a material adverse impact on its business, results of operations and cash flows, resulting from a decrease in customer activity and pricing pressure from its customers.
Government regulations and investors are demanding the oil and gas industry transition to a lower emissions operating environment, including the E&P and oilfield service companies. As a result, we are working with our customers and equipment manufacturers to transition to a lower emissions profile. The transition to lower emissions equipment is capital intensive and could require us to convert our conventional Tier II equipment to lower emissions equipment. If we are unable to quickly transition to lower emissions equipment, the demand for our services could be adversely impacted.
Although the oil and gas industry is currently depressed, we still believe the Permian Basin, our primary area of operation, is the leading basin with the lowest break-even production cost in the United States. If the oil and gas industry recovers, we believe there will be increased demand for pressure pumping services in the Permian Basin. If market conditions remain depressed for a longer period of time, our profitability and future cash flows will be negatively impacted, and as a result, we may be required to record additional asset impairment charges in future periods.
Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to holiday seasons, inclement winter weather and exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating results in November and December, even in a stable commodity price and operations environment.
2020 Operational Highlights
Over the course of the year ended December 31, 2020:
• we experienced a significant decline in pressure pumping equipment utilization and demand for our services, resulting from the combined effect of COVID-19 and the energy industry disruptions, which negatively impacted our operations;
• our average effectively utilized fleet count was approximately 10 active fleets, a 58% decrease from approximately 24 active fleets in 2019;
• we continued to test and develop, alongside the equipment manufacturer, our existing DuraStim® equipment; and
• we improved our existing processes and internal controls in 2020.
2020 Financial Highlights
Financial highlights for the year ended December 31, 2020:
• revenue decreased $1,263.1 million, or 61.5%, to $789.2 million, as compared to $2,052.3 million for the year ended December 31, 2019, primarily a result of the decrease in demand for pressure pumping services following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity;
• cost of services (exclusive of depreciation and amortization) decreased $886.1 million or 60.3% to $584.3 million, as compared to $1,470.4 million for the year ended December 31, 2019, primarily a result of our
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lower utilization and activity levels, following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity; cost of services as a percentage of revenue increased to 74.0% in 2020 compared to 71.6% for the year ended December 31, 2019;
• general and administrative expenses, inclusive of stock-based compensation, decreased $18.3 million, or 17.4% to $86.8 million, as compared to $105.1 million for the year ended December 31, 2019;
• the total impairment expense recorded during the year December 31, 2020 was approximately $38.0 million compared to $3.4 million during the year ended December 31, 2019;
• net loss was $107.0 million, compared to a net income of $163.0 million for the year ended December 31, 2019. Diluted net loss per common share was $1.06, compared to diluted net income per common share of $1.57 for the year ended December 31, 2019. Adjusted EBITDA was approximately $141.5 million, compared to $519.1 million for the year ended December 31, 2019 (see reconciliation of Adjusted EBITDA to net income in the subsequent section “How We Evaluate Our Operations”); and
• maintained a conservative balance sheet, with cash of $69 million and no debt as of December 31, 2020 .
Actions to Address the Economic Impact of COVID-19 and Decline in Commodity Prices
Since March 2020, we initiated several actions to mitigate the anticipated adverse economic conditions for the immediate future and to support our financial position, liquidity and the efficient continuity of our operations as follows:
◦ Growth Capital: we cancelled substantially all our planned growth capital expenditures for the second half of 2020. Our 2021 capital expenditures will be driven by customer activity levels and demand for our pressure pumping services;
◦ Other Expenditures: we significantly reduced our maintenance expenditures and field level consumable costs due to our reduced activity levels in 2020. In 2021, we will continue to seek lower pricing and cost saving measures for our expendable items, materials used in day-to-day operations and large component replacement parts;
◦ Labor Force Reductions: we reduced our workforce by over 60% between April and May 2020 due to the changing activity levels for our services; in 2021, we will continue to make appropriate adjustments to our workforce to reflect outlook related to our customers’ activity levels;
◦ Working Capital: we have negotiated more favorable payment terms with certain of our larger vendors and are continuing to increase our diligence in collecting and managing our portfolio of accounts receivables.
We are continuing to evaluate and consider additional cost saving measures. We will continue to prioritize the safety and welfare of our employees and customers through these turbulent times caused in part by COVID-19 and the depressed energy market.
Our Assets and Operations
Through our pressure pumping segment, which includes cementing operations, we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. Our modern hydraulic fracturing fleets have been designed to handle Permian Basin specific operating conditions and the region’s increasingly high‑intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. We plan to continually reinvest in our equipment to ensure optimal performance and reliability.
In addition to our core pressure pumping segment operations, we also offer a suite of complementary well completion and production services, including coiled tubing and other services. We believe these complementary
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services create operational efficiencies for our customers and could allow us to capture a greater portion of their capital spending across the lifecycle of a well in the future.
How We Generate Revenue
We generate revenue primarily through our pressure pumping segment, and more specifically, by providing hydraulic fracturing services to our customers. We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also provide personnel and services that are tailored to meet each of our customers’ needs. We charge our customers on a per‑job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant and chemicals to be used and other parameters of the job. We also could generate revenue from idle fees from Pioneer in certain circumstances when committed fleets are idled.
In addition to hydraulic fracturing services, we generate revenue through the complementary services that we provide to our customers, including cementing, coiled tubing and other related services. These complementary services are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services.
Demand for our services is largely dependent on oil and natural gas prices, and our customers’ well completion budgets and rig count. Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. WTI oil prices declined significantly in 2015 and 2016 to approximately $30 per barrel, but subsequently recovered in 2017. However, in 2020, oil and natural gas prices were highly volatile. The average WTI oil prices per barrel were approximately $39, $57 and $65 for the years ended December 31, 2020, 2019 and 2018, respectively. In March 2020, WTI oil prices declined significantly, to a low of approximately $20 per barrel towards the end of March 2020. On March 3, 2021, the W TI oil price was approximat ely $62 per bar rel. If WTI oil prices decline or continue to be depressed and do not improve or stabilize, demand for our services may be negatively impacted, which could result in a significant decrease in our profitability and cash flows. We monitor the oil and natural gas prices and the Permian Basin rig count to enable us to more effectively plan our business and forecast the demand for our services.
The historical weekly average Permian Basin rig count based on the Baker Hughes Company rig count information were as follows:
Year Ended December 31,
Drilling Type (Permian Basin) 2020 2019 2018
Directional 1 5 6
Horizontal 212 405 418
Vertical 8 32 43
Total 221 442 467
Average Permian Basin rig count to U.S rig count 51.0 % 46.9 % 45.2 %
Costs of Conducting our Business
The principal direct costs involved in operating our business are direct labor, expendables and other direct costs.
Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly attributable to the effective delivery of services are included in our operating costs. Direct lab or costs amounted to 22.7% and 19.6% of total costs of service for the years ended December 31, 2020 and 2019, respectively. The percentage increase was primarily attributable to the decrease in our revenue, resulting from customer pricing
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pressure and also the increase in the number of our customers directly sourcing certain expendables like sand, diesel and chemical, as discussed below, which had the effect of reducing our revenues.
Expendables. Expendables include the product and freight costs associated with proppant, chemicals and other consumables used in our pressure pumping and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable pro duct costs comprised approximately 37.6%, and 40.8% of total costs of service for the years ended December 31, 2020 and 2019, respectively. The percentage decrease in our expendable product cost in 2020 is primarily attributable to the increase in the number of customers sourcing these expendables directly from the vendors, and overall depressed sand prices, which has the effect of reducing our revenues.
Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our hydraulic fracturing fleet and other equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are capitalized and are not included in other direct costs. Other direct costs were 39.7% and 39.6% of total costs of service for the years ended December 31, 2020 and 2019, respectively.
How We Evaluate Our Operations
Our management uses a variety of financial metrics, Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.
Adjusted EBITDA and Adjusted EBITDA Margin
We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock-based compensation, and (iii) other unusual or nonrecurring (income)/expenses, such as impairment charges, severance, costs related to asset acquisitions, costs related to SEC investigation and class action lawsuits and one-time professional and advisory fees. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.
Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (income) expenses and items outside the control of our management team (such as income taxes). Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income (loss), operating income (loss), cash flow from operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles in the United States of America (“GAAP”).
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Note Regarding Non‑GAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP (“non-GAAP”), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring (income) expenses and items outside the control of the Company. Net income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA and Adjusted EBITDA margin 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 analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted EBITDA and Adjusted EBITDA margin in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Reconciliation of net income (loss) to Adjusted EBITDA ($ in thousands):
Pressure
Pumping
All Other
Total
Year ended December 31, 2020
Net income (loss)
$ (68,271) $ (38,749) $ (107,020)
Depreciation and amortization
148,659 4,631 153,290
Interest expense
1 2,382 2,383
Income tax benefit — (27,480) (27,480)
Loss on disposal of assets
56,659 1,477 58,136
Impairment expense 36,907 1,095 38,002
Stock‑based compensation
— 9,100 9,100
Other expense
— 874 874
Other general and administrative expense (1)
— 13,038 13,038
Retention bonus and severance expense 75 1,065 1,140
Adjusted EBITDA
$ 174,030 $ (32,567) $ 141,463
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Pressure
Pumping All Other Total
Year ended December 31, 2019
Net income (loss)
$ 281,090 $ (118,080) $ 163,010
Depreciation and amortization
139,348 5,956 145,304
Interest expense
51 7,090 7,141
Income tax expense
— 50,494 50,494
Loss on disposal of assets
106,178 633 106,811
Impairment expense — 3,405 3,405
Stock‑based compensation
— 7,776 7,776
Other expense
— 717 717
Other general and administrative expense (1)
— 25,208 25,208
Deferred IPO bonus, retention bonus and severance expense 7,093 2,110 9,203
Adjusted EBITDA
$ 533,760 $ (14,691) $ 519,069
Pressure
Pumping All Other Total
Year ended December 31, 2018
Net income (loss)
$ 253,196 $ (79,334) $ 173,862
Depreciation and amortization
83,404 4,734 88,138
Interest expense
— 6,889 6,889
Income tax expense
— 51,255 51,255
Loss on disposal of assets
59,962 (742) 59,220
Stock‑based compensation
— 5,482 5,482
Other expense
— 663 663
Other general and administrative expense (1)
2 203 205
Deferred IPO bonus
1,832 977 2,809
Adjusted EBITDA
$ 398,396 $ (9,873) $ 388,523
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(1) During the years ended December 31, 2020 and 2019, other general and administrative expense primarily relates to nonrecurring professional fees paid to external consultants in connection with the Company’s expanded audit committee review, SEC investigation and shareholder litigation. All nonrecurring professional fees incurred after the end of June 2020 are in connection with the pending SEC investigation and shareholder litigation. The other general and administrative expense during the year ended December 31, 2018 primarily relates to legal settlements.
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Results of Operations
We conduct our business through three operating segments: hydraulic fracturing, cementing and coiled tubing. In March 2020, the Company shut down its flowback operating segment and subsequently disposed of the assets for approximately $1.6 million. In September 2020, the Company disposed of all of its drilling rigs and ancillary assets for approximately $0.5 million and shut down its drilling operations. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment—pressure pumping.
The comparability of the results of operations for the years ended December 31, 2020 and 2019 have been impacted by the decrease in demand for pressure pumping services following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity during the year ended December 31, 2020.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
($ in thousands, except percentages)
Year Ended December 31, Change
2020 2019 Variance %
Revenue $ 789,232 $ 2,052,314 $ (1,263,082) (61.5) %
Less (Add):
Cost of services (1)
584,279 1,470,356 (886,077) (60.3) %
General and administrative expense (2)
86,768 105,076 (18,308) (17.4) %
Depreciation and amortization 153,290 145,304 7,986 5.5 %
Impairment expense 38,002 3,405 34,597 1,016.1 %
Loss on disposal of assets 58,136 106,811 (48,675) (45.6) %
Interest expense 2,383 7,141 (4,758) (66.6) %
Other expense 874 717 157 21.9 %
Income tax expense (27,480) 50,494 (77,974) (154.4) %
Net (loss) income $ (107,020) $ 163,010 $ (270,030) (165.7) %
Adjusted EBITDA (3)
$ 141,463 $ 519,069 $ (377,606) (72.7) %
Adjusted EBITDA Margin (3)
17.9 % 25.3 % (7.4) % (29.2) %
Pressure pumping segment results of operations:
Revenue $ 773,474 $ 2,001,627 $ (1,228,153) (61.4) %
Cost of services $ 570,442 $ 1,428,620 $ (858,178) (60.1) %
Adjusted EBITDA $ 174,030 $ 533,760 $ (359,730) (67.4) %
Adjusted EBITDA Margin (4)
22.5 % 26.7 % (4.2) % (15.7) %
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(1) Exclusive of depreciation and amortization.
(2) Inclusive of stock‑based compensation of $9.1 million and $7.8 million for 2020 and 2019, respectively.
(3) For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read “How We Evaluate Our Operations.” Included in our Adjusted EBITDA is idle fees of $47.2 million and $13.3 million for the years ended December 31, 2020 and 2019, respectively.
(4) The non‑GAAP financial measure of Adjusted EBITDA margin for the pressure pumping segment is calculated by taking Adjusted EBITDA for the pressure pumping segment as a percentage of our revenues for the pressure pumping segment.
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Revenue. Revenue decreased 61.5%, or $1,263.1 million, to $789.2 million for the year ended December 31, 2020, as compared to $2,052.3 million for the year ended December 31, 2019. Our pressure pumping segment revenues decreased 61.4%, or $1,228.2 million for the year ended December 31, 2020, as compared to the year ended December 31, 2019. The decreases were primarily attributable to the significant decrease in demand for pressure pumping services, as well as pricing discounts we provided to our customers following the depressed oil prices and slowdown in economic activity resulting from the COVID-19 pandemic. The decrease in demand for our pressure pumping services resulted in a significant decrease in our average effectively utilized fleet count to approximately 10.2 active fleets in 2020 from 23.9 active fleets in 2019. Furthermore, the decrease in our revenue was also driven by the increase in our customers directly sourcing from vendors certain consumables like sand, chemicals and fuel. Included in our revenue for the years ended December 31, 2020 and 2019 was revenue generated from idle fees charged to our customer of approximately $47.2 million and $13.3 million, respectively.
Revenues from services other than pressure pumping decreased 68.9%, or approximately $34.9 million, for the year ended December 31, 2020, as compared to the year ended December 31, 2019. The decrease in revenues from services other than pressure pumping during the year ended December 31, 2020, was primarily attributable to the shutdown of our flowback operations and also a significant reduction in utilization experienced in our coiled tubing operations, which was driven by lower E&P completions activity following the depressed oil prices and impact of the COVID-19 pandemic.
Cost of Services. Cost of services decreased 60.3%, or $886.1 million, to $584.3 million for the year ended December 31, 2020, from $1,470.4 million during the year ended December 31, 2019. Cost of services in our pressure pumping segment decreased $858.2 million during the year ended December 31, 2020, as compared to the year ended December 31, 2019. The decreases were primarily attributable to our lower utilization and activity levels, following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity. As a percentage of pressure pumping segment revenues (including idle fees), pressure pumping cost of services increased to 73.8% for the year ended December 31, 2020, as compared to 71.4% for the year ended December 31, 2019. Excluding idle fees revenue of $47.2 million and $13.3 million for the years ended December 31, 2020 and 2019, respectively, our pressure pumping cost of services as a percentage of pressure pumping revenues for the years ended December 31, 2020 and 2019 was approximately 78.5% and 71.9%, respectively. The increase in our cost of services percentage was primarily attributable to pricing pressure on our services resulting from customer discounts. Our pricing in 2020 was significantly depressed following the economic slowdown caused by COVID-19 pandemic and depressed oil prices.
General and Administrative Expenses. General and administrative expenses decreased 17.4%, or $18.3 million, to $86.8 million for the year ended December 31, 2020, as compared to $105.1 million for the year ended December 31, 2019. The net decrease was primarily attributable to a decrease during 2020 in (i) nonrecurring professional fees of $12.2 million, which was primarily attributable to the Company's expanded audit committee internal review, pending SEC investigation and shareholder litigation, (ii) retention and other bonuses, and severance expense of $8.1 million; (iii) property taxes of $1.6 million, and (iv) $5.0 million in other remaining general and administrative expenses, which was partially offset by a net increase of approximately $7.2 million paid in legal, accounting and consulting professional fees, and stock based compensation expense of $1.3 million.
Depreciation and Amortization. Depreciation and amortization increased 5.5%, or $8.0 million, to $153.3 million for the year ended December 31, 2020, as compared to $145.3 million for the year ended December 31, 2019. The increase was primarily attributable to the overall increase in our fixed asset base as of December 31, 2020.
Impairment Expense. During the year ended December 31, 2020, the depressed market conditions, crude oil prices and negative near-term outlook for the utilization of certain of our equipment, resulted in the Company recording an impairment expense of approximately $38.0 million, of which $9.4 million relates to goodwill impairment and $28.6 million relates to property and equipment impairment. The substantial portion of our impairment expense relates to our pressure pumping segment. During the year ended December 31, 2019, we recorded $3.4 million property and equipment impairment expense in connection with our drilling rigs and flowback assets.
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Loss on Disposal of Assets. Loss on the disposal of assets decreased 45.6%, or $48.7 million, to $58.1 million for the year ended December 31, 2020, as compared to $106.8 million for the year ended December 31, 2019. The decrease was primarily attributable to a decrease in utilization resulting from a reduction in the operational intensity of our equipment during 2020. Upon sale or retirement of property and equipment, including certain major components like fluid ends and power ends of our pressure pumping equipment that are replaced, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets.
Interest Expense. Interest expense decreased 66.6%, or $4.8 million, to $2.4 million for the year ended December 31, 2020, as compared to $7.1 million for the year ended December 31, 2019. The decrease in interest expense was primarily attributable to a decrease in our average debt balance in 2020 compared to 2019.
Other Expense. Other expense was relatively flat at $0.9 million for the year ended December 31, 2020, similar to $0.7 million for the year ended December 31, 2019. Our other expense primarily comprised of our lenders administration fees.
Income Tax Expense. Income tax benefit was $27.5 million for the year ended December 31, 2020, as compared to income tax expense of $50.5 million for the year ended December 31, 2019. The income tax benefit recorded during the year ended December 31, 2020 is primarily attributable to the Company ending in a pre-tax loss position in 2020 as compared to a pre-tax income in 2019. Our effective tax rate was 20.4% during the year ended December 31, 2020 compared to 23.7% during the year ended December 31, 2019.
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Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our revolving credit facility (“ABL Credit Facility”). Our primary uses of cash will be to continue to fund our operations, support growth opportunities and satisfy debt payments, if any. Our borrowing base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable. Our borrowing base as of December 31, 2020 was approximately $55.6 million and was approxi mately $48.9 million as of March 3, 2021. Changes to our operational activity levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility. We believe our remaining monthly availability under our ABL Credit Facility will be adversely impacted if the current depressed oil and gas market conditions continue or worsen.
As of December 31, 2020, we had no borrowings under our ABL Credit Facility and our total liquidity was $120.7 million, consisting of cash and cash equivalents of $68.8 million and $51.9 million of availability under our ABL Credit Facility.
As of March 5, 2021, we had no borrowings under our ABL Credit Facility and our total liquidity was approximately $89.6 million, consisting of cash and cash equivalents of $44.4 million and $45.2 million of availability under our ABL Credit Facility.
During the second quarter of 2020 and through July 2020 , when demand for our services was significantly depressed following the rapidly rising health crisis associated with the COVID-19 pandemic and the energy industry disruptions led by depressed WTI crude oil prices, the Company experienced a decrease in its liquidity. If there is a reduction in the COVID-19 infection rate and the ongoing distribution and administration of COVID-19 vaccines lead to a gradual recovery in crude oil prices, we would expect demand for crude oil and consequently the demand for our pressure pumping services to improve during 2021. Combined with our cost reduction initiatives, we have slowly increased our liquidity position over the second half of 2020 and into 2021 and expect our liquidity to continue to gradually increase in 2021, if market conditions continue to improve. The current market conditions resulting from the COVID-19 pandemic are rapidly changing and there could be a new outbreak of a COVID-19 variant. Our future revenue, results of operations and cash flows could be negatively impacted if the COVID-19 pandemic is not contained or if the vaccines currently distributed and administered to people are not as effective as anticipated, and if current market conditions do not improve.
There can be no assurance that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business or meet our future long-term liquidity requirements.
Cash and Cash Flows
The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the years ended December 31, 2020 and 2019, respectively.
Year Ended December 31,
($ in thousands)
2020 2019
Net cash provided by operating activities
$ 139,124 $ 455,290
Net cash used in investing activities
$ (94,217) $ (495,299)
Net cash (used in) provided by financing activities
$ (125,171) $ 56,345
Operating Activities
Net cash provided by operating activities was $139.1 million for the year ended December 31, 2020, as compared to $455.3 million for the year ended December 31, 2019. The net decrease of $316.2 million was primarily due to the reduction in our activity levels in 2020, resulting from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted our o perations. The net decrease in cash
provided by operating activities was also impacted by the timing of our receivable collections from our customers and payment to our vendors.
Investing Activities
Net cash used in investing activities decreased to $94.2 million for the year ended December 31, 2020, from $495.3 million for the year ended December 31, 2019. The net decrease in our cash used in investing activities was primarily attributable to the reduction in growth and maintenance capital expenditures in 2020 following the lower number of pressure pumping active fleets, equipment rotation (resulting in lower intensity on our pressure pumping equipment) and the depressed demand for our pressure pumping services. During the year ended December 31, 2019, the Company made a cash payment of approximately $110.0 million in connection with the Pioneer Pressure Pumping Acquisition and paid approximately $145.3 million for 108,000 HHP of DuraStim® hydraulic fracturing equipment and turbines (including an option payment of $6.1 million to purchase an additional 108,000 HHP of DuraStim® equipment). The remaining cash payments in 2019 were incurred in connection with our maintenance capital expenditures and other growth initiatives.
Financing Activities
Net cash used in financing activities was $125.2 million for the year ended December 31, 2020, compared to net cash provided of $56.3 million for the year ended December 31, 2019. The net decrease in cash flow from financing activities during the year ended December 31, 2020 was primarily driven by the repayment of our outstanding borrowings under ABL Credit Facility of $130.0 million, compared to net borrowings of $60.0 million during the year ended December 31, 2019. During the year ended December 31, 2020, we received cash flow from our insurance financing arrangement of $6.8 million and made repayments of $1.3 million related to our insurance financing.
Credit Facility and Other Financing Arrangements
ABL Credit Facility
Our ABL Credit Facility, as amended, has a total borrowing capacity of $300 million (subject to the Borrowing Base limit), with a maturity date of December 19, 2023. The ABL Credit Facility has a borrowing base of 85% of monthly eligible accounts receivable less customary reserves (the "Borrowing Base"). The Borrowing Base as of December 31, 2020 was approximately $55.6 million. The ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size or the Borrowing Base or (ii) $22.5 million. Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company.
Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero. The weighted average interest rate under our ABL Credit Facility for the year e nded December 31, 2020 was 3.6%.
In March 2020, we obtained a waiver from our lenders under the ABL Credit Facility to extend the time period for us to provide our lenders the Company’s audited financial statements for the year ended December 31, 2019 to July 31, 2020, which we have provided to our lenders.
As of December 31, 2020, we had no borrowings outstanding under our ABL Credit Facility. During the year ended December 31, 2020, we repaid all borrowings under our ABL Credit Facility of approximately $130.0 million with cash flows from operations and our available cash. Our objective is to maintain a conservative leverage ratio throughout 2021.
Off Balance Sheet Arrangements
We had no material off balance sheet arrangements as of December 31, 2020.
Capital Requirements, Future Sources and Use of Cash
Capital expenditures incurred were $81.2 million during the year ended December 31, 2020, as compared to $400.7 million during the year ended December 31, 2019. During the year ended December 31, 2020, we reduced our capital expenditures following the depressed demand for our pressure pumping services as a result of the COVID-19 pandemic and depressed energy market. During the year ended December 31, 2020, the significant portion of our total capital expenditures were comprised of maintenance capital expenditures.
Our future material use of cash will be to fund our capital expenditures. Capital expenditures for 2021 are projected to be primarily related to maintenance capital expenditures to support our existing assets (including costs to convert existing equipment to lower emissions pressure pumping equipment), depending on market conditions and customer demand. Our future capital expenditures depend on our projected operational activity, emission requirements and new technology, among other factors, which could vary throughout the year. Based on our current projected activity levels for 2021, we expect our capital expenditures to range between $115.0 million to $130.0 million (which includes approximately $37.0 million to acquire new Tier IV DGB dual fuel equipment and convert some of our conventional Tier II equipment to lower emissions Tier IV DGB equipment), which is highly dependent on several factors including market conditions. The Company will continue to evaluate the emissions profile of its fleet over the coming years and may convert or retire conventional Tier II equipment in favor of lower emissions equipment. The Company’s decisions regarding the retirement or conversion of equipment or the addition of lower emissions equipment will be subject to a number of factors, including (among other factors) the future impact of the COVID-19 pandemic, prevailing and expected commodity prices, customer demand and requirements and the Company’s evaluation of projected returns on conversion or other capital expenditures. Depending on the impacts of these factors, the Company may decide to retain conventional equipment for a longer period of time or accelerate the retirement, replacement or conversion of that equipment.
In addition, we have option agreements with our equipment manufacturer to purchase an additional 108,000 HHP of DuraStim® hydraulic fracturing equipment thr ough July 31, 2022. We believe the cost to acquire the DuraStim® hydraulic fracturing equipment will be comparable to our previously purchased DuraStim® hydraulic fracturing equipment. In the current economic environment, it is not probable we w ould exercise these options before they expire.
We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility. Our cash flows from operations will be generated from services we provide to our customers and idle fees if a customer (Pioneer) decides to idle committed fleets and we are not able to deploy the idled fleets to another customer. During times when there is a significant reduction in overall demand for our services, the idle fees could represent a material portion of our revenues and cash flows from operations.
Contractual Obligations
The following table presents our contractual obligations and other commitments as of December 31, 2020:
($ in thousands)
Period
Total 1 year or less More than I year
ABL Credit Facility (1)
$ — $ — $ —
Operating leases (2)
863 377 486
Other purchase obligation (3)
1,250 1,250 —
Total $ 2,113 $ 1,627 $ 486
____________________
(1) As of December 31, 2020, we had no borrowings under our ABL Credit Facility. If we decide to borrow from our ABL Credit Facility in the future, interest expense will be charged based on the agreed contractual interest rates. However, we are obligated to pay agency and
commitment fees on unused balance which could be up to approximately $1.2 million annually, depending on our utilization of the ABL Credit Facility.
(2) Operating leases exclude short-term leases and other commitments (see Note 14. Leases and Note 15. Commitments and Contingencies in the financial statements for additional disclosures).
(3) Other purchase obligation relates to vendor related commitments in connection with the supply and storage of certain consumables.
The Company enters into purchase agreements with the Sand suppliers to secure supply of sand in the normal course of its business. The agreements with the Sand suppliers require that we purchase certain sand volumes, which is based on a certain percentage of our overall sand requirements and agreed minimum volumes, otherwise certain penalties may be charged. Under certain of the purchase agreements, a shortfall fee applies if we purchase less than the agreed percentage of our sand requirements or agreed minimum volumes. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes. Our current agreements with Sand suppliers expire at different times prior to April 30, 2022. Our agreed upon sand requirements or minimum volumes are based on certain future events such as our customer demand, which cannot be reasonably estimated.
Recent Accounting Pronouncements
Disclosure concerning recently issued accounting standards is incorporated by reference to “Note 2- Significant Accounting Policies” of our Consolidated Financial Statements contained in this Annual Report.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.
Listed below are the accounting policies that we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.
Property and Equipment
Our property and equipment are recorded at cost, less accumulated depreciation.
Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings.
We primarily retired certain components of equipment such as fluid ends and power ends, rather than the entire pieces of equipment, and the associated loss is recorded in our statement of operations as part of net loss on disposal of assets, which was $58.1 million, $106.8 million and $59.2 million for the years ended December 31, 2020, 2019 and 2018, respectively.
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The estimated useful lives and salvage values of property and equipment is subject to key assumptions such as maintenance, utilization and job variation. Unanticipated future changes in these assumptions could negatively or positively impact our net income (loss). A 10% change in the useful lives of our property and equipment would have resulted in approximately $15.3 million impact on pre-tax loss during the year ended December 31, 2020. Depreciation of property and equipment is provided on the straight‑line method over estimated useful lives as shown in the table below.
Land
Indefinite
Buildings and property improvements
5 - 30 years
Vehicles
1 ‑ 5 years
Equipment
1 ‑ 20 years
Leasehold improvements
5 ‑ 20 years
Impairment of Long-Lived Assets
In accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets , we review the long‑lived assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the asset. Our cash flow forecasts require us to make certain judgments regarding long‑term forecasts of future revenue and costs and cash flows related to the assets subject to review. The significant assumption in our cash flow forecasts is our estimated equipment utilization and profitability. The significant assumption is uncertain in that it is driven by future demand for our services and utilization, which could be impacted by crude oil market prices, future market conditions and technological advancements. Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs, including assumptions related to market based on recent auction sales or selling prices of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future.
During the first quarter of 2020, management determined the reductions in commodity prices driven by the impact of the novel COVID-19 virus and global supply and demand dynamics coupled with the sustained decrease in the Company’s share price were triggering events for asset impairment. Furthermore, in light of the energy industry transition to lower emissions equipment, the Company made a strategic decision in December 2020 to retire approximately 150,000 HHP of our conventional Tier II pressure pumping equipment. As a result of these triggering events, we performed recoverability tests on each of the assets groups and recorded impairment expense during the year ended December 31, 2020 as follows:
• in the first quarter of 2020, we recorded drilling asset impairment of approximately $1.1 million as a result of the negative near-term outlook of our drilling assets utilization;
• in the first quarter of 2020, we recorded an impairment expense of $6.1 million in our pressure pumping reportable segment related to our options deposit to purchase additional DuraStim® equipment, for which the options expire at various times through the end of July 2022, as it is not probable we would exercise our options due to the events described above; and
• in the fourth quarter of 2020, we recorded an impairment expense of approximately $21.3 million, in our pressure pumping reportable segment, in connection with our planned retirement of approximately 150,000 HHP of our conventional Tier II pressure pumping equipment.
If the crude oil market declines or the demand for our services does n ot recover, and if our equipment remains idle or under‑utilized, the estimated fair value of such equipment may decline, which could result in future impairment charges. Though the impacts of variations in any of these factors can have compounding or off‑setting impacts, a 10% decline in the estimated future cash flows of our existing asset groups will not indicate an impairment.
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Goodwill
Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized. Goodwill is not amortized. We perform an annual impairment test of goodwill as of December 31, or more frequently if circumstances indicate that impairment may exist.
There were no additions to, or disposal of, goodwill during the year ended December 31, 2020. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted active fleet revenue and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, fleet utilization, expected profitability margin, forecasted maintenance capital expenditures, the timing of an anticipated market recovery, and the timing of expected cash flow. As such, our goodwill analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. In March 2020, crude oil prices declined significantly, an indication that a triggering event has occurred, and as such, we recorded in our pressure pumping reportable segment, goodwill impairment expense of $9.4 million during the year ended December 31, 2020. There was no carrying value for goodwill in our balance sheet as of December 31, 2020 because our goodwill carrying value was fully written off during the year.
Income Taxes
Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would not be able to fully realize our deferred tax assets in the future in excess of their net recorded amount, we would record a valuation allowance, which would increase our provision for income taxes. In determining our need for a valuation allowance as of December 31, 2020, we have considered and made judgments and estimates regarding estimated future taxable income. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record additional valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.
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