PROPETRO HOLDING CORP.
The financial information, discussion and analysis that follow should be
read in conjunction with our consolidated financial statements and the related
notes included in the Form 10-K as well as the financial and other information
included therein.
Unless otherwise indicated, references in this "Management's Discussion and
Analysis of Financial Condition and Results of Operations" to the "Company,"
"we," "our," "us" or like terms refer to ProPetro Holding Corp. and its
subsidiary.
Overview
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 ("E&P") of North American
unconventional oil and natural gas resources. Our operations are primarily
focused in the Permian Basin , where we have cultivated long-standing 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 area in the United States , and we believe we are one of the
largest providers of hydraulic fracturing services in the region by hydraulic
horsepower ("HHP").
Our total available HHP as of March 31, 2021 was 1,388,000 HHP, which was
comprised of 15,000 HHP of our new Tier IV Dynamic Gas Blending ("DGB")
equipment, 1,265,000 HHP of conventional Tier II equipment and 108,000 HHP of
our new DuraStim® hydraulic fracturing equipment. During the second quarter of
2021, we expect to take delivery of our remaining committed 35,000 HHP of new
DGB equipment. On average, a fleet consists of approximately 50,000 HHP but
could vary significantly depending on the job design and customer demand at the
wellsite. With the industry transition to lower emissions equipment and
simultaneous fracturing, 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 back up HHP at the
wellsites based on our customers' and operational needs or as we retire and
replace conventional Tier II equipment.
In 2019, we entered into a purchase commitment for 108,000 HHP of DuraStim®
electric powered hydraulic fracturing equipment. Our DuraStim® equipment is
still being tested and has only been deployed to our customers' wellsites on a
limited scale. As we continue with our testing of the equipment, the number of
DuraStim® pumps that constitute a fleet will depend on a combination of factors,
including the ultimate operating performance of DuraStim® pumps following the
completion of testing, the particular shale formation where a well is completed,
customer service requirements and job design. The Company has set a goal to
commercialize its first DuraStim® fleet 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 .
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.
Our competitors include many large and small oilfield services companies,
including Halliburton Company, Liberty Oilfield Services Inc., Nextier Oilfield
Solutions Inc., Patterson-UTI Energy Inc., RPC, Inc., FTS International Inc. and
a number of private and locally-oriented businesses. The markets in which we
operate are highly competitive. To be successful, an oilfield services company
must provide services that meet the specific needs of E&P companies at
competitive prices. Competitive factors impacting sales of our services are
price, reputation, technical expertise, emissions profile, service and equipment
design and quality, and health and safety standards. Although our customers
consider all of these factors, we believe price is a key factor in E&P
companies' criteria in choosing a service provider. However, we have recently
observed the energy industry and our customers shift to lower emissions
equipment, which we believe will be an increasingly important factor in an E&P
company's selection of a service provider. The transition to lower emissions
equipment has been challenging for companies in the service industry because of
the capital requirement, and the depressed energy industry. While we seek to
price our services competitively, we believe many of our customers elect to work
with us based on our operational efficiencies, productivity, equipment quality,
commitment to safety and the ability of our people to handle the most complex
Permian Basin well completions.
Our substantial market presence in the Permian Basin positions us well to
capitalize on drilling and completion activity in the region. Primarily, our
operational focus has been in the Permian Basin's Midland sub-basin, where our
customers have operated. However, we are well positioned to increase our
activity in the Delaware sub-basin in response to demand from our customers.
Over time, we expect the Permian Basin's Midland and Delaware sub-basins to
continue to command a disproportionate share of future North American E&P
spending.
Through our pressure pumping segment (which also includes our cementing
operations), we primarily provide hydraulic fracturing services to E&P companies
in the Permian Basin . Our hydraulic fracturing fleet has been designed to handle
Permian Basin specific operating conditions and the region's increasingly
high-intensity well completions (including simultaneous
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--------------------------------------------------------------------------------hydraulic fracturing), 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. We believe our coiled tubing 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. 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, political instability in oil producing countries, government
regulations (both in the United States and internationally), levels of consumer
demand, adverse weather conditions, and other factors that are beyond our
control.
The global public health crisis associated with the COVID-19 pandemic has
and could continue to have an adverse effect on global economic activity for the
immediate future, has resulted in travel limitations, business closures and the
institution of quarantining and other restrictions on movement and business
operations in many communities. With the slowdown in global economic activity
attributable to COVID-19 beginning in early 2020, the energy industry
experienced a dramatic decline in the demand for energy and crude oil prices,
which impacted our industry and the Company. In addition, global crude oil
prices have been highly volatile especially in 2020 with the overall global
uncertainty related to anticipated production levels for OPEC+ participants and
the impact of COVID-19 pandemic.
In 2020, the combined effect of COVID-19 and the energy industry
disruptions led to a significant decline in WTI crude oil prices to
approximately $21 per barrel at the end of March 2020 . With OPEC+ managing
production levels, the development and administration of COVID-19 vaccines and
the lifting of COVID-19 restrictions in certain areas (both in the United States
and internationally), there has been a gradual recovery in the energy industry
and overall economic activities from its lowest point in 2020. However, there is
still some level of uncertainty in the global market resulting from the COVID-19
pandemic and the risk of an outbreak of a new virus, which could result in
continued depressed global energy demand and declining crude oil prices. As of
May 3, 2021 , the WTI price for a barrel of crude oil was approximately $65 .
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
and is currently at 224 rigs at the end of March 2021 . If the rig count and
market conditions do not continue to improve, the Company expects a material
adverse impact on its business, results of operations and cash flows, resulting
from a decrease in our 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. 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.
Although the oil and gas market has not fully recovered and pricing for our
services is still 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.
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--------------------------------------------------------------------------------Actions to Address the Economic Impact of COVID-19 and Depressed Energy Industry
We initiated several actions to mitigate the anticipated adverse economic
conditions for the immediate future and to support our future financial
position, liquidity and operations as follows:
•Capital Expenditures: our 2021 capital expenditures will be driven by customer
activity levels and demand for our pressure pumping services. Our objective is
to remain capital disciplined.
•Other Expenditures: we will continue to seek competitive pricing and cost
saving measures for our expendable items, logistics, materials used in
day-to-day operations and our large component replacement parts.
•Labor Force: we will continue to make appropriate adjustments to our workforce
to reflect outlook related to our customers' activity levels. We will continue
to explore strategic options to improve our customers' efficiencies and
prioritize safe operations, while maintaining the most efficient headcount.
•Working Capital: we will continue to monitor our payment terms with certain of
our larger vendors and continue to increase our diligence in collecting and
managing our portfolio of accounts receivables.
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 and related costs, costs related to asset
acquisitions and one-time professional 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 GAAP.
Note Regarding Non-GAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are not financial measures
presented in accordance with GAAP ("non-GAAP"), except when specifically
required to be disclosed by GAAP in the financial statements. We believe that
the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful
information to investors in assessing our financial condition and results of
operations because it allows them to compare our operating performance on a
consistent basis across periods by removing the effects of our capital
structure, asset base, nonrecurring expenses (income) and items outside the
control of the Company. Net income (loss) is the GAAP measure most directly
comparable to Adjusted EBITDA. 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 or 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.
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Reconciliation of net (loss) income to Adjusted EBITDA ($ in thousands):
Three
Months Ended
Pressure Pumping All Other Total
Net loss $ (13,675) $ (6,700) $ (20,375)
Depreciation and amortization 32,513 965 33,478
Interest expense - 176 176
Income tax benefit - (6,663) (6,663)
Loss on disposal of assets 13,032 20 13,052
Stock-based compensation - 2,487 2,487
Other income - (1,789) (1,789)
Other general and administrative expense, (net)(1) - (961) (961)
Severance expense - 612 612
Adjusted EBITDA $ 31,870 $ (11,853) $ 20,017
Three Months Ended March 31, 2020
Pressure Pumping All Other Total
Net income (loss) $ 4,308 $ (12,112) $ (7,804)
Depreciation and amortization 38,969 1,236 40,205
Impairment expense 15,559 1,095 16,654
Interest expense 1 1,280 1,281
Income tax expense - (909) (909)
Loss on disposal of assets 19,815 39 19,854
Stock-based compensation - 471 471
Other expense - 3 3
Other general and administrative expense(1) - 5,135 5,135
Retention bonus and severance expense 12 21 33
Adjusted EBITDA $ 78,664 $ (3,741) $ 74,923 (1)Other general and administrative expense, (net) relates to nonrecurring
professional fees paid to external consultants in connection with the Company's
pending
-20-
--------------------------------------------------------------------------------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 coiled tubing operating segment and corporate
administrative expenses (inclusive of our total income tax expense (benefit) and
interest expense) are included in the ''all other'' category. Total corporate
administrative expense for the three months ended March 31, 2021 and 2020 was
$5.0 million and $10.3 million , respectively.
Our hydraulic fracturing operating segment revenue approximated 93.3% and
94.8% of our pressure pumping revenue during the three months ended March 31,
2021 and 2020, respectively.
The following table sets forth the results of operations for the periods
presented:
(in thousands, except for percentages) Three Months Ended Change
March 31, Increase (Decrease)
2021 2020 $ %
Revenue $ 161,458 $ 395,069 $ (233,611) (59.1) %
Less (Add):
Cost of services (1) 123,378 300,848 (177,470) (59.0) %
General and administrative expense (2) 20,201 24,937 (4,736) (19.0) %
Depreciation and amortization 33,478 40,205 (6,727) (16.7) %
Impairment Expense - 16,654 (16,654) (100.0) %
Loss on disposal of assets 13,052 19,854 (6,802) (34.3) %
Interest expense 176 1,281 (1,105) (86.3) %
Other (income) expense (1,789) 3 (1,792) (59,733.3) %
Income tax benefit (6,663) (909) (5,754) 633.0 %
Net loss $ (20,375) $ (7,804) $ (12,571) 161.1 %
Adjusted EBITDA (3) $ 20,017 $ 74,923 $ (54,906) (73.3) %
Adjusted EBITDA Margin (3) 12.4 % 19.0 % (6.6) % (34.7) %
Pressure pumping segment results of
operations:
Revenue $ 158,191 $ 386,919 $ (228,728) (59.1) %
Cost of services $ 119,768 $ 294,224 $ (174,456) (59.3) %
Adjusted EBITDA (3) $ 31,870 $ 78,664 $ (46,794) (59.5) %
Adjusted EBITDA Margin (4) 20.1 % 20.3 % (0.2) % (1.0) %
(1)Exclusive of depreciation and amortization.
(2)Inclusive of stock-based compensation.
(3)For definitions of the non-GAAP financial measures of Adjusted EBITDA and
Adjusted EBITDA margin and reconciliation of Adjusted EBITDA 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 $4.3 million and $1.5 million for the three months ended March 31,
2021 and 2020, 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 revenue for the pressure pumping segment.
-21-
--------------------------------------------------------------------------------
Three Months Ended
Revenue. Revenue decreased 59.1%, or $233.6 million , to $161.5
million during the three months ended March 31, 2021 , as compared to $395.1
million during the three months ended March 31, 2020 . Our pressure pumping
segment revenues decreased 59.1%, or $228.7 million , for the three months ended
March 31, 2021 , as compared to the three months ended March 31, 2020 . 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 10.3 active fleets during the three months
ended March 31, 2021 from approximately 18.6 active fleets for the three months
ended March 31, 2020 . In addition, our revenue for the three months ended
March 31, 2021 was negatively impacted by the severe weather conditions
experienced in February 2021 , resulting in approximately eight days of lost
revenue. Included in our revenue for the three months ended March 31, 2021 and
2020 was revenue generated from idle fees charged to our customer of
approximately $4.3 million and $1.5 million , respectively.
Revenues from services other than pressure pumping decreased 59.9%, or $4.9
million , to $3.3 million for the three months ended March 31, 2021 , as compared
to $8.2 million for the three months ended March 31, 2020 . The decrease in
revenue from services other than pressure pumping was primarily attributable to
the significant reduction in utilization experienced by 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, and the shutdown of
our flowback operations.
Cost of Services. Cost of services decreased 59.0%, or $177.5 million , to
$123.4 million for the three months ended March 31, 2021 , as compared to $300.8
million during the three months ended March 31, 2020 . Cost of services in our
pressure pumping segment decreased $174.5 million for the three months ended
March 31, 2021 , as compared to the three months ended March 31, 2020 . These
decreases were primarily attributable to the significantly lower 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 was 75.7% for the three months ended March 31, 2021 , as compared to
76.0% for the three months ended March 31, 2020 . Excluding idle fees revenue of
$4.3 million and $1.5 million recorded during the three months ended March 31,
2021 and 2020, respectively, our pressure pumping cost of services as a
percentage of pressure pumping revenues for the three months ended March 31,
2021 and 2020, was approximately 77.8% and 76.3%, respectively. Furthermore,
during the three months ended March 31, 2021 the company absorbed certain cost
of services during the eight days of severe weather conditions experienced in
February 2021 , which negatively impacted our profitability.
General and Administrative Expenses. General and administrative expenses
decreased 19.0%, or $4.7 million , to $20.2 million for the three months ended
March 31, 2021 , as compared to $24.9 million for the three months ended
March 31, 2020 . The net decrease was primarily attributable to a decrease during
2021 in nonrecurring professional fees of $6.1 million , which was primarily
attributable to the Company's expanded audit committee internal review, pending
SEC investigation and shareholder litigation, which was offset by a net increase
of approximately $1.4 million in our other remaining general and administrative
expenses.
Impairment Expense. There was no impairment expense recorded during the
three months ended March 31, 2021 , as compared to $16.7 million of goodwill and
equipment impairment expense recorded during the three months ended March 31,
2020 in connection with the then depressed market conditions and utilization of
our equipment.
Depreciation and Amortization. Depreciation and amortization decreased of
16.7%, or $6.7 million , to $33.5 million for the three months ended March 31,
2021 , as compared to $40.2 million for the three months ended March 31, 2020 .
The decrease was primarily attributable to the decrease in our fixed asset base,
part of which was attributable to the impairment of certain fixed assets in
2020.
Loss on Disposal of Assets. Loss on the disposal of assets decreased
34.3%, or $6.8 million , to $13.1 million for the three months ended March 31,
2021 , as compared to $19.9 million for the three months ended March 31, 2020 .
The decrease was primarily attributable to the decrease in equipment
utilization. Upon sale or retirement of property and equipment, including
certain major components 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 86.3%, or $1.1 million , to
$0.2 million for the three months ended March 31, 2021 , as compared to $1.3
million for the three months ended March 31, 2020 . The decrease in interest
expense was primarily attributable to the decrease in our average debt balance
during the three months ended March 31, 2021 compared to the three months ended
March 31, 2020 . The Company repaid all of its borrowings under the ABL Credit
Facility in 2020, and
-22---------------------------------------------------------------------------------
had no outstanding borrowings during the three months ended
Other (Income)/Expense. Other income increased to $1.8 million for the
three months ended March 31, 2021 . The increase in other income is primarily
attributable to the net refund of approximately $2.1 million to the Company from
the sales and excise and use tax audit and partially offset by an expense
related to our lender's commitment fees during the three months ended March 31,
2021 .
Income Taxes. Total income tax benefit was $6.7 million resulting in an
effective tax rate of 24.6% for the three months ended March 31, 2021 , as
compared to income tax benefit of $0.9 million or an effective tax rate of 10.4%
for the three months ended March 31, 2020 . The income tax benefit recorded in
the three months ended March 31, 2021 is primarily attributable to the higher
pre-tax loss in 2021 as compared to 2020. Furthermore, the change in the
effective tax rate from 10.4% to 24.6% in the three months ended March 31, 2021
was primarily attributable to nondeductible expenses and discrete items such as
stock compensation, reducing the benefit recorded for the pre-tax loss during
the three months ended March 31, 2020 .
-23-
--------------------------------------------------------------------------------Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii)
operating cash flows and (iii) borrowings under our ABL Credit Facility, if any.
Our primary uses of cash will be to continue to fund our operations, support
growth opportunities and satisfy future debt payments, if any. Our borrowing
base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable.
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 March 31, 2021 , we had no borrowings under our ABL Credit Facility,
and our total liquidity was approximately $113.7 million , consisting of cash and
cash equivalents of $55.9 million and $57.8 million of availability under our
ABL Credit Facility.
As of May 3, 2021 , our total liquidity was approximately $110.9 million ,
consisting of cash and cash equivalents of $51.1 million and $59.8 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 led by depressed WTI crude oil prices, the Company
experienced a significant decrease in its liquidity. In 2021, we have
experienced a gradual recovery in the energy industry and crude oil prices and a
reduction in the COVID-19 infection rate and the administration of COVID-19
vaccines, which we believe will improve the demand for crude oil and
consequently the demand for our pressure pumping services, thus improving our
future liquidity. However, the current market conditions resulting from the
COVID-19 pandemic could rapidly change and there could be a new outbreak of a
COVID-19 variant or the vaccines may not be as effective as anticipated, which
could negatively impact the demand for our services and our future revenue,
results of operations and cash flows.
There can be no assurance that 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 on 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.
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 March 31, 2021 was approximately $61.5 million and was
approximately $63.5 million as of May 3, 2021 . 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. There were no borrowings under the ABL Credit Facility
for the three months ended March 31, 2021 . As of March 31, 2020 , our outstanding
borrowings under the ABL Credit Facility were $110 million , which was
subsequently fully repaid before the end of 2020.
In July 2017 , the United Kingdom's Financial Conduct Authority , which
regulates LIBOR, announced that it intends to phase out LIBOR by the end of
2021. At the present time, the ABL Credit Facility is subject to LIBOR rates but
has a term that extends beyond the end of 2021 when LIBOR will be phased out. We
have not yet pursued any technical amendment or other contractual alternative to
address this matter. We are currently evaluating the potential impact of
eventual replacement of the LIBOR interest rate.
-24-
--------------------------------------------------------------------------------Future Sources and Use of Cash and Contractual Obligations
Our future primary use of cash will be to fund 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 our existing conventional Tier II equipment to lower emissions equipment-Tier IV DGB equipment.
We expect that our currently anticipated capital expenditures will be
funded by existing cash, cash flows from operations, and, if needed, borrowings
under our ABL Credit Facility. However, as noted elsewhere in this quarterly
report, we will continually evaluate opportunities to improve our service
offerings and other investment and acquisition opportunities that we believe
would enhance the competitiveness of our business. Depending upon market
conditions and other factors, we may issue equity and debt securities or take
other actions necessary to fund our future investment or acquisitions.
In addition, we have option agreements with our equipment manufacturer to
purchase additional 108,000 HHP of DuraStim® hydraulic fracturing equipment
through 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 that we will exercise these options before they expire.
In the normal course of business, we enter into various contractual
obligations and routine growth and maintenance capital expenditures that impact
our future liquidity. There were no other known future material contractual
obligations as of March 31, 2021 .
Cash and Cash Flows
The following table sets forth the historical cash flows for the three
months ended
Three Months Ended March 31,
($ in thousands) 2021 2020
Net cash provided by operating activities $ 17,008 $ 61,724
Net cash used in investing activities $ (22,270) $ (46,557)
Net cash used in financing activities $ (7,651) $ (20,486) Cash Flows From Operating Activities
Net cash provided by operating activities was $17.0 million for the three
months ended March 31, 2021 , compared to $61.7 million for the three months
ended March 31, 2020 . The net decrease of $44.7 million was primarily due to the
decrease in our activity levels resulting from the decrease in the demand for
our services, driven by the depressed crude oil prices and economic impact of
the COVID-19 pandemic on our industry, and partially offset with the timing of
collections of our receivables from customers and payments to vendors. Our
effectively utilized fleet count decreased to approximately 10.3 active fleets
during the three months ended March 31, 2021 from approximately 18.6 active
fleets for the three months ended March 31, 2020 .
Cash Flows From Investing Activities
Net cash used in investing activities decreased to $22.3 million for the
three months ended March 31, 2021 , from $46.6 million for the three months ended
March 31, 2020 . The decrease was primarily attributable to the lower maintenance
capital expenditures associated with lower activity levels during the three
months ended March 31, 2021 , compared to higher activity levels and associated
higher maintenance capital expenditures during the three months ended March 31,
2020 .
Cash Flows From Financing Activities
Net cash used in financing activities decreased to $7.7 million for the
three months ended March 31, 2021 , from $20.5 million for the three months ended
March 31, 2020 . The decrease in cash from financing activities during the three
months ended March 31, 2021 was primarily driven by the repayment of
$20.0 million of our borrowings under our ABL Credit Facility during the three
months ended March 31, 2020 , compared to no repayments of borrowings during the
three months ended March 31, 2021 .
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--------------------------------------------------------------------------------Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of
There have been no material changes during the three months ended March
31, 2021 to the methodology applied by our management for critical accounting
policies previously disclosed in our Form 10-K. Please refer to Part II, Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations-Critical Accounting Policies and Estimates" in our Form 10-K for a
discussion of our critical accounting policies and estimates.
Recently Issued Accounting Standards
Disclosure concerning recently issued accounting standards is incorporated by reference to Note 2 of our Condensed Consolidated Financial Statements (Unaudited) contained in this Form 10-Q.
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