PROPETRO HOLDING CORP. 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 forwardlooking 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 forwardlooking 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 endedDecember 31, 2019 and the comparison of our results of operations for the years endedDecember 31, 2020 and 2019, which may be found in our Annual Report on Form 10-K for the year endedDecember 31, 2020 , filed with theSEC onMarch 5, 2021 . 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 toProPetro Holding Corp. and its subsidiary. Overview Our Business We are a Midland, Texasbased oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the E&P of North American oil and natural gas resources. Our operations are primarily focused in thePermian Basin , where we have cultivated longstanding customer relationships with some of the region's most active and wellcapitalized E&P companies.The Permian Basin is widely regarded as one of the most prolific oilproducing areas inthe United States , and we believe we are one of the leading providers of hydraulic fracturing services in the region by HHP. Our total available HHP atDecember 31, 2021 was 1,423,000 HHP, which was comprised of 90,000 HHP of our Tier IV DGB equipment, 1,225,000 HHP of conventional Tier II equipment and 108,000 HHP of our DuraStim® electric hydraulic fracturing equipment. Our fleet could range from approximately 50,000 to 80,000 HHP depending on the job design and customer demand at the wellsites. With the industry transition to lower emissions equipment and Simul-Frac, in addition to several other changes to our customers' job designs, we believe that our available fleet capacity could decline if we decide to reconfigure our fleets to increase active HHP and backup HHP at the wellsites. InSeptember 2021 , we placed an order with our equipment manufacturers for 125,000 HHP of Tier IV DGB equipment for additional conversions, which we expect to be delivered at different times through the first half of 2022. In 2019, we entered into a purchase commitment for 108,000 HHP of DuraStim® electric powered hydraulic fracturing equipment. In addition to DuraStim® fleets, we are also evaluating other electric and alternative pressure pumping solutions. InDecember 2021 , we disposed of our two gas turbines initially purchased to provide electrical power to our DuraStim® fleets but as determined they were an inefficient power solution in the field. In the future, we may lease electrical power equipment from a third party or rely on our customers to provide power solutions for our electric equipment. Our substantial market presence in thePermian Basin positions us well to capitalize on drilling and completion activity in the region. Primarily, our operational focus has been in thePermian Basin's Midland sub-basin, where our customers have operated. However, we have recently increased our operations in theDelaware sub-basin and are well-positioned to support further increases to our activity in this area in response to demand from our customers. Over time, we expect thePermian Basin's Midland andDelaware sub-basins to continue to command a disproportionate share of future North American E&P spending. 34 -------------------------------------------------------------------------------- Through our pressure pumping segment (which also includes our cementing operations), we primarily provide hydraulic fracturing services to E&P companies in thePermian Basin . Our hydraulic fracturing fleet has been designed to handle the operating conditions commonly utilized in thePermian Basin and the region's increasingly high-intensity well completions (including Simul-Frac, which involves fracturing multiple wellbores at the same time), which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. In addition to our core pressure pumping segment operations, which includes our cementing operations, we also offer coiled tubing services. Through our coiled tubing services segment, we seek to create operational efficiencies for our customers, which could allow us to capture a greater portion of their capital spending across the lifecycle of a well.
Pioneer Pressure Pumping Acquisition
On December 31, 2018 , we consummated the purchase of pressure pumping and
related assets of Pioneer and Pioneer Pumping Services, LLC in the Pioneer
Pressure Pumping Acquisition. The pressure pumping assets acquired included
hydraulic fracturing pumps of 510,000 HHP, four coiled tubing units and the
associated equipment maintenance facility. In connection with the acquisition,
we became a long-term service provider to Pioneer under the Pioneer Services
Agreement, providing pressure pumping and related services for a term of up to
10 years; provided, that Pioneer has the right to terminate the Pioneer Services
Agreement, in whole or part, effective as of December 31 of each of the calendar
years of 2022, 2024 and 2026. Pioneer can increase the number of committed
fleets prior to December 31, 2022 . Pursuant to the Pioneer Services Agreement,
the Company is entitled to receive compensation if Pioneer were to idle
committed fleets ("idle fees"); however, we are first required to use all
economically reasonable efforts to deploy the idled fleets to another customer.
At the present, we have eight fleets committed to Pioneer. During times when
there is a significant reduction in overall demand for our services, the idle
fees could represent a material portion of our revenues.
While management believes our relationship with Pioneer will continue
beyond December 31, 2022 , if Pioneer elects to terminate the Pioneer Services
Agreement effective December 31, 2022 , or seeks to renegotiate the terms on
which we provide services to Pioneer, it could have a material adverse effect on
our future financial condition, results of operations and cash flows.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is influenced
by a combination of long-term, short-term and cyclical trends, including
domestic and international supply and demand for oil and gas, current and
expected future prices for oil and gas and the perceived stability and
sustainability of those prices, and capital investments of E&P companies toward
their development and production of oil and gas reserves. The oil and gas
industry is also impacted by general domestic and international economic
conditions such as supply chain disruptions and inflation, political instability
in oil producing countries, government regulations (both in the United States
and internationally), levels of consumer demand, adverse weather conditions, and
other factors that are beyond our control.
The global public health crisis associated with the COVID-19 pandemic could
continue to have an adverse effect on global economic activity for the
foreseeable future. Some of the challenges resulting from the COVID-19 pandemic
that have impacted our business include restrictions on movement of personnel
and associated gatherings, shortage of skilled labor, cost inflation and supply
chain disruptions. Additionally, with most of the large, capitalized E&P
companies in the United States , including our customers, closely managing their
operating budget and exercising capital discipline, we do not currently expect
significant increases in crude oil production over the short-to-medium term.
Furthermore, OPEC+ has indicated that they will continue with their plans to
manage production levels by gradually increasing crude oil output. With the
tightness in crude oil production and growing demand for crude oil, there has
been a significant increase in rig count and WTI crude oil prices have increased
to over $90 per barrel in February 2022 from its recent lowest point of $20 per
barrel in March 2020 . The Permian Basin rig count has increased significantly
from approximately 179 at the beginning of 2021 to approximately 294 at the end
of 2021, according to Baker Hughes . Although crude oil prices are currently
35
--------------------------------------------------------------------------------
at a 7-year high, the oilfield services industry, including the pressure pumping
segment, has not fully recovered as evidenced by continued depressed pricing for
most of our services, and shortages of skilled labor force in the Permian Basin ,
coupled with rising inflationary costs. However, we still believe that the
Permian Basin , our primary area of operation, will be the most attractive basin
to E&P companies and should command higher prices and associated profitability,
if the overall demand for crude oil and our services continues to increase.
Government regulations and investors are demanding the oil and gas industry
transition to a lower emissions operating environment, including the upstream
and oilfield services companies. As a result, we are working with our customers
and equipment manufacturers to transition to a lower emissions profile.
Currently, a number of lower emission solutions for pumping equipment, including
Tier IV DGB, electric, direct drive gas turbine and other technologies have been
developed, and we expect additional lower emission solutions will be developed
in the future. We are continually evaluating these technologies and other
investment and acquisition opportunities that would support our existing and new
customer relationships. The transition to lower emissions equipment is quickly
evolving and will be capital intensive. Over time, we may be required to convert
substantially all of our conventional Tier II equipment to lower emissions
equipment. If we are unable to quickly transition to lower emissions equipment
and meet our and our customers' emissions goals, the demand for our services
could be adversely impacted.
The Permian Basin rig count increase, WTI crude oil price increase and cost
inflation could be indicative of an energy market recovery. If the rig count and
market conditions continue to improve, including improved customers' pricing and
labor availability, and we are able to meet our customers' lower emissions
equipment demands, we believe our operational and financial results will also
continue to improve. However, if market conditions do not improve, and we are
unable to increase our pricing or pass-through future cost increases to our
customers, there could be a material adverse impact on our business, results of
operations and cash flows.
Our results of operations have historically reflected seasonal tendencies,
typically in the fourth quarter, relating to the holiday season, inclement
winter weather and exhaustion of our customers' annual budgets. As a result, we
typically experience declines in our operating and financial results in November
and December, even in a stable commodity price and operations environment.
2021 Operational Highlights
Over the course of the year ended
•although we gradually captured improved pricing during the year, the recent energy industry disruption and impact of COVID-19 pandemic continued to adversely impact overall demand for and pricing of our services;
•we experienced rapidly increasing inflationary cost resulting from labor and supply chain tightness, which negatively impacted our profitability and cash flows;
•our average effectively utilized fleet count was approximately 12 active fleets, a 20% increase from approximately 10 active fleets in 2020;
•we transitioned 90,000 HHP of our equipment portfolio to lower emissions, Tier IV DGB equipment. In 2022, we plan to convert an additional 125,000 HHP to Tier IV DGB equipment, with total conversion costs expected to approximate$74 million ; and
•we continued to test and develop, alongside the equipment manufacturer, our existing DuraStim® equipment.
36
--------------------------------------------------------------------------------2021 Financial Highlights
Financial highlights for the year ended
•revenue increased$85.3 million , or 10.8%, to$874.5 million , as compared to$789.2 million for the year endedDecember 31, 2020 , primarily a result of the increase in demand for pressure pumping services following the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity; •cost of services (exclusive of depreciation and amortization) increased$78.0 million or 13.3% to$662.3 million , as compared to$584.3 million for the year endedDecember 31, 2020 , primarily a result of our higher utilization and activity levels, following the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity in 2020; cost of services as a percentage of revenue increased to 75.7% in 2021 compared to 74.0% for the year endedDecember 31, 2020 ; •general and administrative expenses, inclusive of stock-based compensation, decreased$3.8 million , or 4.4% to$82.9 million , as compared to$86.8 million for the year endedDecember 31, 2020 ;
•no impairment expense recorded during the year
•net loss was$54.2 million , compared to a net loss of$107.0 million for the year endedDecember 31, 2020 . Diluted net loss per common share was$0.53 , compared to diluted net loss per common share of$1.06 for the year endedDecember 31, 2020 . Adjusted EBITDA was approximately$135.0 million , compared to$141.5 million for the year endedDecember 31, 2020 (see reconciliation of Adjusted EBITDA to net income in the subsequent section "How We Evaluate Our Operations");
•generated cash of approximately
•our total liquidity was
•no debt as of
Actions to Address the Economic Impact of COVID-19
Since March 2020 , we initiated several actions to mitigate the anticipated
adverse economic conditions for the immediate future and to support our
financial position, liquidity and the efficient continuity of our operations as
follows:
•Growth Capital: our operations were driven by more dedicated work from our
customers. Our capital expenditure program was focused on maintaining existing
dedicated demand for our equipment. We reduced capital investment in speculative
growth.
•Other Expenditures: we strategically managed our maintenance program in line
with our projected activity levels. We continued to seek lower pricing and cost
saving measures for our expendable items, materials used in day-to-day
operations and large component replacement parts. In addition, with the supply
chain disruptions, we worked closely with our vendors to better plan our future
needs and accelerated purchases of certain components and spare parts;
•Labor Force: we implemented several strategies including pay adjustments of
approximately 8% to retain and attract skilled workforce that will support our
operations;
37
-------------------------------------------------------------------------------- •Working Capital: we have negotiated more favorable payment terms with certain of our larger vendors, strategically disposed of certain assets to improve our liquidity position and continue to actively manage our portfolio of accounts receivables; and •Customer Pricing: we continue to have ongoing pricing conversations with our customers to permit us to earn an appropriate return on our equipment and capital investments and to cover rising inflationary cost resulting from the impact of COVID-19 on labor force, supply chain and our operations in general.
Our Assets and Operations
Through our pressure pumping segment, which includes cementing operations,
we primarily provide hydraulic fracturing services to E&P companies in the
Permian Basin . Our hydraulic fracturing fleets have been designed to handle
Permian Basin specific operating conditions and the region's increasingly
highintensity well completions, which are characterized by longer horizontal
wellbores, more frac stages per lateral and increasing amounts of proppant per
well. We plan to continually reinvest in our equipment to ensure optimal
performance and reliability.
In addition to our core pressure pumping segment operations, we also offer
a suite of complementary well completion and production services, including
coiled tubing and other services. We believe these complementary services create
operational efficiencies for our customers and could allow us to capture a
greater portion of their capital spending across the lifecycle of a well in the
future.
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 perjob basis, in which we set pricing terms after receiving
full specifications for the requested job, including the lateral length of the
customer's wellbore, the number of frac stages per well, the amount of proppant
and chemicals to be used and other parameters of the job. We also could generate
revenue from idle fees from our customers in certain circumstances when
committed fleets are idled.
In addition to hydraulic fracturing services, we generate revenue through
the complementary services that we provide to our customers, including
cementing, coiled tubing and other related services. These complementary
services are provided through various contractual arrangements, including on a
turnkey contract basis, in which we set a price to perform a particular job, or
a daywork contract basis, in which we are paid a set price per day for our
services. 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. The average WTI oil prices per barrel were approximately $68 , $39
and $57 for the years ended December 31, 2021 , 2020 and 2019, respectively. In
February 2022 , the WTI oil price was over $90 per barrel. If the WTI oil price
declines in the future or remains highly volatile, demand for our services may
be negatively impacted, which could result in a significant decrease in our
future profitability and cash flows. We monitor the oil and natural gas prices
and the Permian Basin rig count to enable us to more effectively plan our
business and forecast the demand for our services.
38
--------------------------------------------------------------------------------
The historical weekly average
Year Ended December 31,
Drilling Rig Type (Permian Basin) 2021 2020 2019
Directional 2 1 5
Horizontal 227 212 405
Vertical 11 8 32
Total 240 221 442
Average Permian Basin rig count to U.S rig
count 50.5 % 51.0 % 46.9 %
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 or indirectly attributable to the effective
delivery of services are included in our operating costs. Direct labor costs
amounted to 22.4% and 22.7% of total costs of service for the years ended
December 31, 2021 and 2020, respectively.
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
product costs comprised approximately 41.8%, and 37.6% of total costs of service
for the years ended December 31, 2021 and 2020, respectively. The percentage
increase in our expendable product cost in 2021 was primarily attributable to
the increase in our activity levels and higher freight cost.
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 35.8% and 39.7% of total costs of service for the years ended
December 31, 2021 and 2020, respectively. The percentage decrease in 2021 was
primarily driven by most of our customers directly sourcing diesel and pricing
improvement.
How We Evaluate Our Operations
Our management uses 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, insurance
recoveries, 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.
39
--------------------------------------------------------------------------------
Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures
utilized by our management and other users of our financial statements such as
investors, commercial banks, and research analysts, to assess our financial
performance because it allows us and other users to compare our operating
performance on a consistent basis across periods by removing the effects of our
capital structure (such as varying levels of interest expense), asset base (such
as depreciation and amortization), nonrecurring (income) expenses and items
outside the control of our management team (such as income taxes). Adjusted
EBITDA and Adjusted EBITDA margin have limitations as analytical tools and
should not be considered as an alternative to net income (loss), operating
income (loss), cash flow from operating activities or any other measure of
financial performance presented in accordance with generally accepted accounting
principles in the United States of America ("GAAP").
Note Regarding NonGAAP 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 (loss) income to Adjusted EBITDA ($ in thousands):
Pressure
Pumping All Other Total
Year ended
Net loss $ (12,723) $
(41,462)
Depreciation and amortization 129,478 3,899 133,377
Interest expense - 614 614
Income tax benefit - (14,252) (14,252)
Loss (gain) on disposal of assets 64,903 (257) 64,646
Stockbased compensation - 11,519 11,519
Other income - (873) (873)
Other general and administrative expense (1) - (6,471) (6,471)
Severance expense 30 602 632
Adjusted EBITDA $ 181,688 $ (46,681) $ 135,007
40
--------------------------------------------------------------------------------
Pressure
Pumping All Other Total
Year ended December 31, 2020
Net 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
Stockbased 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
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
Stockbased 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 ____________________
(1)During the years endedDecember 31, 2021 , 2020 and 2019, other general and administrative expense (net of reimbursement from insurance carriers) primarily relates to nonrecurring professional fees paid to external consultants in connection with our audit committee review,SEC investigation and shareholder litigation, net of insurance recoveries. During the years endedDecember 31, 2021 , 2020 and 2019, we received reimbursement of approximately$9.8 million ,$0.6 million and$0 , respectively, from our insurance carriers in connection with theSEC investigation and shareholder litigation. 41 --------------------------------------------------------------------------------
Results of Operations
We conduct our business through three operating segments: hydraulic fracturing, cementing and coiled tubing. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment-pressure pumping.
Year Ended
($ in thousands, except percentages)
Year Ended December 31, Change
2021 2020 Variance %
Revenue $ 874,514 $ 789,232 $ 85,282 10.8 %
Less (Add):
Cost of services (1) 662,266 584,279 77,987 13.3 %
General and administrative expense (2) 82,921 86,768 (3,847) (4.4) %
Depreciation and amortization 133,377 153,290 (19,913) (13.0) %
Impairment expense - 38,002 (38,002) (100.0) %
Loss on disposal of assets 64,646 58,136 6,510 11.2 %
Interest expense 614 2,383 (1,769) (74.2) %
Other expense (income) (873) 874 1,747 199.9 %
Income tax benefit (14,252) (27,480) (13,228) (48.1) %
Net loss $ (54,185) $ (107,020) $ (52,835) (49.4) %
Adjusted EBITDA (3) $ 135,007 $ 141,463 $ (6,456) (4.6) %
Adjusted EBITDA Margin (3) 15.4 % 17.9 % (2.5) % (14.0) %
Pressure pumping segment results of
operations:
Revenue $ 857,642 $ 773,474 $ 84,168 10.9 %
Cost of services $ 647,570 $ 570,442 $ 77,128 13.5 %
Adjusted EBITDA $ 181,688 $ 174,030 $ 7,658 4.4 %
Adjusted EBITDA Margin (4) 21.2 % 22.5 % (1.3) % (5.8) %
____________________
(1) Exclusive of depreciation and amortization.
(2) Inclusive of stockbased compensation of
(3) For definitions of the nonGAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read "How We Evaluate Our Operations." Included in our Adjusted EBITDA is idle fees of$9.5 million and$47.2 million for the years endedDecember 31, 2021 and 2020, respectively. (4) The nonGAAP 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. 42 -------------------------------------------------------------------------------- Revenue. Revenue increased 10.8%, or$85.3 million , to$874.5 million for the year endedDecember 31, 2021 , as compared to$789.2 million for the year endedDecember 31, 2020 . Our pressure pumping segment revenues increased 10.9%, or$84.2 million for the year endedDecember 31, 2021 , as compared to the year endedDecember 31, 2020 . The increases were primarily attributable to the significant increase in demand for pressure pumping services, following the rebound from the depressed oil prices and slowdown in economic activity resulting from the COVID-19 pandemic. The increase in demand for our pressure pumping services resulted in an approximate 20% increase in our average effectively utilized fleet count to approximately 12 active fleets in 2021 from 10 active fleets in 2020. Included in our revenue for the years endedDecember 31, 2021 and 2020 was revenue generated from idle fees charged to a certain customer of approximately$9.5 million and$47.2 million , respectively. Revenues from services other than pressure pumping increased 7.1%, or approximately$1.1 million , for the year endedDecember 31, 2021 , as compared to the year endedDecember 31, 2020 . The increase in revenues from services other than pressure pumping during the year endedDecember 31, 2021 , was primarily attributable to the increase in utilization experienced in our coiled tubing operations, which was driven by increased E&P completions activity following the rebound from the depressed oil prices and impact of the COVID-19 pandemic. Cost of Services. Cost of services increased 13.3%, or$78.0 million , to$662.3 million for the year endedDecember 31, 2021 , from$584.3 million during the year endedDecember 31, 2020 . Cost of services in our pressure pumping segment increased$77.1 million during the year endedDecember 31, 2021 , as compared to the year endedDecember 31, 2020 . The increases were primarily attributable to our higher utilization and activity levels, following the rebound from the depressed oil prices and economic slowdown caused by the COVID-19 pandemic that negatively impacted E&P completions activity in 2020. As a percentage of pressure pumping segment revenues (including idle fees), pressure pumping cost of services increased to 75.5% for the year endedDecember 31, 2021 , as compared to 73.8% for the year endedDecember 31, 2020 . Excluding idle fees revenue of$9.5 million and$47.2 million for the years endedDecember 31, 2021 and 2020, respectively, our pressure pumping cost of services as a percentage of pressure pumping revenues for the years endedDecember 31, 2021 and 2020 was approximately 76.4% and 78.5%, respectively. The decrease was a result of increased customer activity levels, which is consistent with our increased fleet utilization, coupled with significant pricing pressure in 2020. General and Administrative Expenses. General and administrative expenses decreased 4.4%, or$3.8 million , to$82.9 million for the year endedDecember 31, 2021 , as compared to$86.8 million for the year endedDecember 31, 2020 . The net decrease was primarily attributable to the decrease in (i) nonrecurring advisory and professional fees of$19.4 million , which was primarily attributable to the Company's expanded audit committee internal review,SEC investigation and shareholder litigation, (ii) legal and professional fees of$3.9 million , which was partially offset by net increases of (iii)$15.8 million in payroll expenses, (iv)$2.4 million of stock based compensation expense, (v)$1.2 million in insurance expense and (vi)$0.1 million in other remaining general and administrative expenses. Depreciation and Amortization. Depreciation and amortization decreased 13.0%, or$19.9 million , to$133.4 million for the year endedDecember 31, 2021 , as compared to$153.3 million for the year endedDecember 31, 2020 . The decrease was primarily attributable to the overall decrease in our fixed asset base as ofDecember 31, 2021 , partly attributable to the impairment of certain fixed assets in 2020. Impairment Expense. There was no impairment expense during the year endedDecember 31, 2021 . During the year endedDecember 31, 2020 , the depressed market conditions, crude oil prices and negative near-term outlook for the utilization of certain of our equipment, resulted in the Company recording an impairment expense of approximately$38.0 million , of which$9.4 million related to goodwill impairment and$28.6 million related to property and equipment impairment. The substantial portion of our impairment expense in 2020 related to our pressure pumping segment. Loss on Disposal of Assets. Loss on the disposal of assets increased 11.2%, or$6.5 million , to$64.6 million for the year endedDecember 31, 2021 , as compared to$58.1 million for the year endedDecember 31, 2020 . The increase was primarily attributable to an increase in utilization resulting from an increase in the operational intensity of our equipment during 2021. Upon sale or retirement of property and equipment, including certain major 43 -------------------------------------------------------------------------------- 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 74.2%, or$1.8 million , to$0.6 million for the year endedDecember 31, 2021 , as compared to$2.4 million for the year endedDecember 31, 2020 . The decrease in interest expense was primarily attributable to a decrease in our financing arrangements and zero debt in 2021, compared to 2020. Our interest expense consist primarily of amortization of our original loan cost. In 2021, we have zero debt under our ABL Credit Facility. Other Expense (Income). Other income increased to approximately$0.9 million for the year endedDecember 31, 2021 , as compared to$0.9 million in expense for the year endedDecember 31, 2020 . The increase in other income is primarily attributable to the net refund of approximately$2.1 million to the Company from a sales and excise and use tax audit and partially offset by an expense related to our lender's commitment fees during the year endedDecember 31, 2021 , as compared to the year endedDecember 31, 2020 . Income Tax Benefit. Income tax benefit was$14.3 million for the year endedDecember 31, 2021 , as compared to income tax benefit of$27.5 million for the year endedDecember 31, 2020 . The reduction in income tax benefit recorded during the year endedDecember 31, 2021 is primarily attributable to the Company projecting a much lower pre-tax loss in 2021 as compared to that in 2020. Furthermore, there was no significant change in the effective tax rate from 20.8% during the year endedDecember 31, 2021 , compared to 20.4% during the year endedDecember 31, 2020 . 44
--------------------------------------------------------------------------------
Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii)
operating cash flows and (iii) borrowings under our revolving credit facility
("ABL Credit Facility"). Our cash is primarily used to fund our operations,
support growth opportunities and satisfy debt payments, if any. Our borrowing
base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable
(the "borrowing base"). Our borrowing base as of December 31, 2021 was
approximately $61.1 million and was approximately $79.0 million as of
February 18, 2022 . Changes to our operational activity levels have an impact on
our total eligible accounts receivable, which could result in significant
changes to our borrowing base and therefore our availability under our ABL
Credit Facility. We believe our remaining monthly availability under our ABL
Credit Facility will be adversely impacted if oil and gas market conditions
decline in the future.
As of December 31, 2021 , we had no borrowings under our ABL Credit Facility
and our total liquidity was $169.3 million , consisting of cash and cash
equivalents of $111.9 million and $57.4 million of availability under our ABL
Credit Facility.
As of February 18, 2022 , we had no borrowings under our ABL Credit Facility
and our total liquidity was approximately $151.3 million , consisting of cash and
cash equivalents of $76.0 million and $75.3 million of availability under our
ABL Credit Facility.
In 2020 when demand for our services was significantly depressed following
the rapidly rising health crisis associated with the COVID-19 pandemic and the
energy industry disruptions, the Company experienced a significant decrease in
its liquidity. However, with the gradual recovery in the energy industry and
increase in demand for our services in 2021, our liquidity position has
gradually improved and this improvement has continued into the beginning of
2022, as market conditions have continued to improve, although we expect our
overall liquidity to decline during 2022 as we make additional capital
investments. Moreover, the current market conditions resulting from the COVID-19
pandemic have and may in the future change rapidly and there could be a new
outbreak of a COVID-19 variant that could result in travel restrictions,
business closure and institution of quarantining and/or other activity
restrictions, which could negatively impact our future operations, revenue,
profitability and cash flows if not contained or if the vaccines currently
distributed and administered to people are not as effective as anticipated in
curbing the spread of any such new COVID-19 variant.
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
Year Ended December 31,
($ in thousands) 2021 2020
Net cash provided by operating activities
Operating Activities
Net cash provided by operating activities was $154.7 million for the year
ended December 31, 2021 , as compared to $139.1 million for the year ended
December 31, 2020 . The net increase of $15.6 million was primarily due to the
reduction in our net loss, resulting from an increase in our activity levels in
2021, and the rebound from the depressed oil prices and economic slowdown caused
by the COVID-19 pandemic that negatively impacted our
operations in 2020. The net increase in cash provided by operating activities
was also slightly impacted by the timing of our receivable collections from our
customers and payment to our vendors.
Investing Activities
Net cash used in investing activities increased to $104.3 million for the
year ended December 31, 2021 , from $94.2 million for the year ended December 31,
2020 . The net increase in our cash used in investing activities was primarily
attributable to our investment in Tier IV DGB equipment. Included in our net
cash used for investing activities in 2021 was a cash payment of $45.3 million
for new Tier IV DGB equipment. The remaining cash payments in 2021 were incurred
in connection with our maintenance capital expenditures and other growth
initiatives. Our cash flow from investing activities was partially offset by
$36.0 million of cash generated from the sale of our two turbine generators in
December 2021 .
Financing Activities
Net cash used in financing activities was $7.3 million for the year ended
December 31, 2021 , compared to net cash used of $125.2 million for the year
ended December 31, 2020 . The net decrease in cash flow from financing activities
during the year ended December 31, 2021 was primarily driven by no borrowings or
repayments under our ABL Credit Facility in 2021 compared to repayment of
borrowings of $130.0 million during the year ended December 31, 2020 . During the
year ended December 31, 2021 , net cash outflow in connection with insurance
financing was approximately $5.5 million , whereas during the year ended
December 31, 2020 we received net cash inflow of $5.5 million .
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 as of
December 31, 2021 was approximately $61.1 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.
As of
Off Balance Sheet Arrangements
We had no material off balance sheet arrangements as of
Capital Requirements, Future Sources and Use of Cash
Capital expenditures incurred were $165.2 million during the year ended
December 31, 2021 , as compared to $81.2 million during the year ended
December 31, 2020 . During the year ended December 31, 2020 , we reduced our
capital expenditures following the depressed demand for our pressure pumping
services as a result of the COVID-19 pandemic and depressed energy market. The
significant portion of our total capital expenditures were comprised of
maintenance capital expenditures.
Our future material use of cash will be to fund our capital expenditures.
Capital expenditures for 2022 are projected to be primarily related to
maintenance capital expenditures to support our existing pressure pumping
assets, costs to convert some existing equipment to lower emissions pressure
pumping equipment, strategic purchases and other ancillary equipment purchases,
subject to market conditions and customer demand. Our future capital
expenditures depend on our projected operational activity, emission requirements
and planned conversions to lower emissions equipment, among other factors, which
could vary significantly throughout the year. Based on our current plan and
projected activity levels for 2022, we expect our capital expenditures to range
between $250.0 million to $300.0 million . We could incur significant additional
capital expenditures if our projected activity levels increase during the course
of the year, inflation and supply chain tightness continues to adversely impact
on our operations or we invest in new or different lower emissions equipment.
The Company will continue to evaluate the emissions profile of its fleet over
the coming years and may, depending on market conditions, convert or retire
additional conventional Tier II equipment in favor of lower emissions equipment.
The Company's decisions regarding the retirement or conversion of equipment or
the addition of lower emissions equipment will be subject to a number of
factors, including (among other factors) the availability of equipment,
including parts and major components, supply chain disruptions, prevailing and
expected commodity prices, customer demand and requirements and the Company's
evaluation of projected returns on conversion or other capital expenditures.
Depending on the impacts of these factors, the Company may decide to retain
conventional equipment for a longer period of time or accelerate the retirement,
replacement or conversion of that equipment.
In addition, we have option agreements with our equipment manufacturer to
purchase an additional 108,000 HHP of DuraStim® hydraulic fracturing equipment
through
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
($ in thousands) Period
Total 1 year or less More than I year
ABL Credit Facility (1) $ - $ - $ -
Operating leases(2) 487 389 98
Total $ 487 $ 389 $ 98
____________________
(1)As of December 31, 2021 , we had no borrowings under our ABL Credit Facility.
If we decide to borrow from our ABL Credit Facility in the future, interest
expense will be charged based on the agreed contractual interest rates. However,
we are obligated to pay agency and commitment fees on unused balance which could
be up to approximately $1.2 million annually, depending on our utilization of
the ABL Credit Facility.
(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).
We enter into purchase agreements with Sand suppliers to secure supply of
sand in the normal course of our business. The agreements with the Sand
suppliers require that we purchase minimum volume of sand, based primarily on a
certain percentage of our sand requirements from our customers or in certain
situations based on predetermined fixed minimum volumes, otherwise certain
penalties (shortfall fees) may be charged. 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 December 31,
2025 . Our agreed upon sand requirements or minimum volumes are based on certain
future events such as our customer demand, which cannot be reasonably estimated.
If the activity level of our customers declines and the future demand for our
services is materially and adversely affected, we may be required to pay for
more sand from one of our Sand suppliers than we need in the performance of our
services, regardless of whether we take physical delivery of such sand. In such
an event, we may be required to pay shortfall fees or other penalties under the
purchase agreement, which could have a material adverse effect on our business,
financial condition, or results of operations.
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 $64.6 million , $58.1 million and $106.8 million for the years
ended December 31, 2021 , 2020 and 2019, respectively.
45
--------------------------------------------------------------------------------
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 $13.3 million impact on
pre-tax loss during the year ended December 31, 2021 . Depreciation of property
and equipment is provided on the straightline 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 LongLived Assets, we review the longlived 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 longterm 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 longlived 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.
If the crude oil market declines or the demand for our services does not
recover, and if our equipment remains idle or underutilized, the estimated fair
value of such equipment may decline, which could result in future impairment
charges. Though the impacts of variations in any of these factors can have
compounding or offsetting impacts, a 10% decline in the estimated future cash
flows of our existing asset groups will not indicate an impairment.
Our DuraStim® equipment is yet to be commercialized. If we are not able to
successfully commercialize the DuraStim® equipment, and are not able to deploy
the equipment for alternative uses, we will incur impairment losses on the
carrying value of the DuraStim® equipment. As of December 31, 2021 , the carrying
value of our DuraStim® equipment is approximately $90 million .
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 ofDecember 31 , or more frequently if circumstances indicate that impairment may exist. There were no additions to, or disposal of, goodwill during the year endedDecember 31, 2021 . The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted active fleet revenue and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, fleet utilization, expected profitability margin, forecasted maintenance capital expenditures, the timing of an anticipated market recovery, and the timing of expected cash flow. 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. InMarch 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 46 --------------------------------------------------------------------------------
during the year ended
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, 2021 , 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.
47
--------------------------------------------------------------------------------
© Edgar Online, source
