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 growth-oriented, 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
currently one of the largest providers of hydraulic fracturing services in the
region by hydraulic horsepower ("HHP").
On December 31, 2018 , we consummated the purchase of pressure pumping and
related assets of Pioneer Natural Resources USA, Inc. ("Pioneer") and Pioneer
Pumping Services, LLC (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 a Pressure Pumping Services Agreement (the "Pioneer Services
Agreement"), providing pressure pumping and related services for a term of up to
10 years; provided, that Pioneer has the right to terminate the Pioneer Services
Agreement, in whole or part, effective as of December 31 of each of the calendar
years of 2022, 2024 and 2026. Pioneer can increase the number of committed
fleets prior to December 31, 2022 . Pursuant to the Pioneer Services Agreement,
the Company is entitled to receive compensation if Pioneer were to idle
committed fleets ("idle fees"); however, we are first required to use all
economically reasonable effort to deploy the idled fleets to another customer.
At the present, we have eight fleets committed to Pioneer. During times when
there is a significant reduction in overall demand for our services, the idle
fees could represent a material portion of our revenues.
Changes to our customers' well design, shale formations, operating
conditions and new technology have resulted in continuous changes to the number
of pumps, or units, that constitute a fleet. As a result of the asymmetric
nature of the number of pumps that constitute a fleet across our customer base,
which we believe will continue to evolve, we view HHP to also be an appropriate
metric to measure our available hydraulic fracturing capacity. Our total
available HHP at June 30, 2019 was 1,415,000 HHP in conventional equipment. In
2019, we entered into a purchase commitment for 108,000 HHP of DuraStim®
hydraulic fracturing pumps, and in December 2019 , we have received 54,000 HHP of
the DuraStim® hydraulic fracturing pumps, with the remaining pumps of 54,000 HHP
expected to be delivered before the end of 2020. At December 31, 2019 , our total
available HHP was 1,469,000 HHP, which was comprised of 1,415,000 HHP of
conventional HHP and 54,000 HHP of our newly purchased DuraStim® hydraulic
fracturing technology. With the continuous evaluation and changes to the number
of pumps or HHP that constitute a fleet, we believe that our available fleet
capacity could decline as we reconfigure our fleets to increase active HHP and
back up HHP based on our customers' and operational needs. We also have an
option to purchase up to an additional 108,000 HHP of DuraStim® hydraulic
fracturing pumps in the future through April 30, 2021 . The DuraStim® technology
is powered by electricity. In 2019, we purchased two gas turbines to provide
electrical power for the DuraStim® fleets. The electrical power sources for
future DuraStim® fleets are still being evaluated and could either be supplied
by the Company, customers or a third-party supplier.
Our competitors include many large and small oilfield services companies,
including RPC, Inc., Halliburton Company, Patterson-UTI Energy Inc., Nextier
Oilfield Solutions Inc., Inc. , Liberty Oilfield Services Inc., Superior Energy
Services Inc., Schlumberger Limited, FTS International Inc. and a number of
private companies. Although we believe price is a key factor in E&P companies'
criteria in choosing a service provider, we believe that other important factors
include operational efficiency, technical expertise, service and equipment
quality, and health and safety standards. While we seek to price our services
competitively, we believe many of our customers elect to work with us based on
our deep local roots, operational expertise, the capability of our modern fleet
to handle the most complex Permian Basin well completions, and commitment to
safety and reliability.
Our substantial market presence in the Permian Basin positions us well to
capitalize on drilling and completion activity in the region. Historically, our
operational focus has been in the Permian Basin's Midland sub-basin, where our
customers have primarily operated. However, with increasing levels of Delaware
sub-basin activity, we have recently expanded our presence in
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the
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 modern hydraulic fracturing fleet has been designed to
handle Permian Basin specific operating conditions and the region's increasingly
high-intensity well completions, which are characterized by longer horizontal
wellbores, more stages per lateral and increasing amounts of proppant per well.
The majority of our fleet has been delivered in recent years, and we continue to
fully maintain our equipment through the recent industry downturn to ensure
optimal performance and reliability.
In addition to our core pressure pumping segment operations, which includes
our cementing 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. Our vertical drilling rigs have been idled since 2016
and if the market for vertical drilling does not improve, and the equipment
continues to be idled, the estimated fair value for the drilling rigs may
decline, thus resulting in future impairment charges.
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 is anticipated to continue to have an adverse effect on global economic
activity for the immediate future and has resulted in travel restrictions,
business closures and the institution of quarantining and other restrictions on
movement in many communities. The slowdown in global economic activity
attributable to COVID-19 has resulted in a dramatic decline in the demand for
energy which directly impacts our industry and the Company. In addition, global
crude oil prices experienced a collapse starting in early March 2020 as a direct
result of failed negotiations between OPEC and Russia . In response to the global
economic slowdown, OPEC had recommended a decrease in production levels in order
to accommodate reduced demand. Russia rejected the recommendation of OPEC as a
concession to U.S. producers. After the failure to reach an agreement, Saudi
Arabia , a dominant member of OPEC , and other Persian Gulf OPEC members announced
intentions to increase production and offer price discounts to buyers in certain
geographic regions.
As the breadth of the COVID-19 health crisis expanded throughout the month
of March 2020 and governmental authorities implemented more restrictive measures
to limit person-to-person contact, global economic activity continued to decline
commensurately. The associated impact on the energy industry has been adverse
and continued to be exacerbated by the unresolved conflict regarding production.
In the second week of April 2020 , OPEC reconvened to discuss the matter of
production cuts in light of unprecedented disruption and supply and demand
imbalances that expanded since the failed negotiations in early March 2020 .
Tentative agreements were reached to cut production by up to 10 million barrels
of oil per day, or BOPD, with allocations to be made among the OPEC+
participants. Some of these production cuts went into effect in the first half
of May 2020 , however, commodity prices remain depressed as a result of an
increasingly utilized global storage network and near-term demand loss
attributable to the COVID-19 health crisis and related economic slowdown.
The combined effect of COVID-19 and the energy industry disruptions led to
a decline in WTI crude oil prices of approximately 67 percent from the beginning
of January 2020 , when prices were approximately $62 per barrel, through the end
of March 2020 , when they were just above $20 per barrel. Overall crude oil price
volatility has continued despite apparent agreement among OPEC+ regarding
production cuts and as of June 17, 2020 , the WTI price for a barrel of crude oil
was approximately $38 .
Despite a significant decline in drilling and completion activity by U.S.
producers starting in mid-March 2020 , domestic supply continues to exceed demand
which has led to significant operational stress with respect to capacity
limitations associated with storage, pipeline and refining infrastructure,
particularly within the Gulf Coast region. The combined effect of the
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--------------------------------------------------------------------------------aforementioned factors is anticipated to have a continuing adverse impact on the industry in general and our operations specifically.
The Permian Basin rig count has decreased significantly from approximately 403 at the beginning of 2020 to 175 inMay 2020 , according toBaker Hughes , and may continue to decline if current market conditions do not improve. As a result of the depressed market conditions and events, the Company expects a material adverse impact on the services we provide resulting from our customers shutting down completions of wells and pricing pressure from our customers to reduce the prices of our services. We expect the reduction in the number of wells completion activities and the pricing pressure from our customers to have a negative impact on our future revenue, results of operations and cash flows. Although the oil and gas market is currently depressed, we still believe thePermian Basin , our primary area of operation, is the leading basin with the lowest break-even production cost inthe United States . If the market rebounds, we believe there will be increased demand for pressure pumping services in thePermian Basin where we operate. 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. The seasonal tendencies and the current depressed oil and gas market conditions could result in a longer time recovery time in the oil and gas industry thereby significantly impacting on revenue, results of operations and cash flows for a longer period of time beyond 2020.
Actions to Address the Economic Impact of COVID-19 and Decline in Commodity Prices
Since March 2020 , we initiated several actions to mitigate the anticipated
adverse economic conditions for the immediate future and to support our
financial position, liquidity and the efficient continuity of our operations as
follows:
• Growth Capital. We cancelled substantially all our planned growth
capital expenditures for the remainder of 2020.
• Other Expenditures. We significantly reduced our maintenance
expenditures and field level consumable costs due to ourreduced
activity levels. We have been seeking lower pricing for our
expendable items, materials used in day-to-day operations and large
component replacement parts. Also, we have been internalizing certain
support services that were outsourced.
• Labor Force Reductions. We have reduced our workforce by over 60% due
to the changing activity levels for our services. We willcontinue to
make appropriate adjustments to our workforce to reflectoutlook
related to activity levels.
• Compensation Related Costs. The directors and officers have
voluntarily reduced compensation at different levels up to 20%. We
have taken efforts to manage work schedules, primarily related to
hourly employees, to minimize overtime costs.
• Working Capital. We have negotiated more favorable paymentterms with
certain of our larger vendors and are continuing to increase our
diligence in collecting and managing our portfolio of accounts
receivables.
We are continuing to evaluate and consider additional cost saving measures. We will continue to prioritize the safety and welfare of our employees and customers through these turbulent times.
How We Evaluate Our Operations
Our management uses a variety of financial metrics, Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.
Adjusted EBITDA and Adjusted EBITDA margin
We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators
of performance. We define EBITDA as our earnings, before (i) interest expense,
(ii) income taxes and (iii) depreciation and amortization. We define Adjusted
EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) loss/(gain)
on extinguishment of debt, (iii) stock-based compensation, and (iv) other
unusual or nonrecurring (income)/expenses, such as impairment charges,
severance, costs related to our initial public offering and costs related to
asset acquisitions or one-time professional fees. Adjusted EBITDA margin
reflects our Adjusted EBITDA as a percentage of our revenues.
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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 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 income (loss) to adjusted EBITDA ($ in thousands):
Three Months Ended June 30, 2019
Pressure Pumping All Other Total
Net income (loss) $ 64,230 $ (28,097 ) $ 36,133
Depreciation and amortization 34,023 1,459 35,482
Interest expense 22 2,004 2,026
Income tax expense - 10,272 10,272
Loss on disposal of assets 31,117 81 31,198
Stock-based compensation - 2,840 2,840
Other expense - 276 276
Other general and administrative expense(1) - 6,540 6,540
Retention bonus expense 1,795 - 1,795
Adjusted EBITDA $ 131,187 $ (4,625 ) $ 126,562
Three Months Ended June 30, 2018
Pressure Pumping All Other Total
Net income (loss) $ 57,524 $ (18,433 ) $ 39,091
Depreciation and amortization 20,042 1,234 21,276
Interest expense - 2,231 2,231
Income tax expense - 12,052 12,052
Loss (gain) on disposal of assets 19,823 (833 ) 18,990
Stock-based compensation - 1,443 1,443
Other expense - 182 182
Other general and administrative expense(1) 2 16 18
Deferred IPO bonus expense 427 258 685
Adjusted EBITDA $ 97,818 $ (1,850 ) $ 95,968
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Six Months Ended June 30, 2019
Pressure Pumping All Other Total
Net income (loss) $ 162,324 $ (56,386 ) $ 105,938
Depreciation and amortization 65,806 2,793 68,599
Interest expense 22 3,906 3,928
Income tax expense - 32,164 32,164
Loss on disposal of assets 50,123 302 50,425
Stock-based compensation - 4,669 4,669
Other expense - 464 464
Other general and administrative expense (1) - 6,540 6,540
Deferred IPO bonus and retention bonus expense 3,953 157 4,110
Adjusted EBITDA $ 282,228 $ (5,391 ) $ 276,837
Six Months Ended June 30, 2018
Pressure Pumping All Other Total
Net income (loss) $ 110,458 $ (34,659 ) $ 75,799
Depreciation and amortization 37,805 2,406 40,211
Interest expense - 3,492 3,492
Income tax expense - 22,406 22,406
Loss (gain) on disposal of assets 27,651 (996 ) 26,655
Stock-based compensation - 2,201 2,201
Other expense - 412 412
Other general and administrative expense (1) 2 18 20
Deferred IPO bonus expense 965 551 1,516
Adjusted EBITDA $ 176,881 $ (4,169 ) $ 172,712 (1) Other general and administrative expense primarily relates to nonrecurring
professional fees paid to external consultants in connection with the
Expanded Audit Committee Review and advisory services of $6.5 million in
2019, and legal settlement in 2018.
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Results of Operations
We conduct our business through five operating segments: hydraulic
fracturing (inclusive of acidizing), cementing, coil tubing, flowback, and
drilling. For reporting purposes, the hydraulic fracturing and cementing
operating segments are aggregated into our one reportable segment-pressure
pumping. All other operating segments and corporate administrative expenses
(inclusive of our total income tax expense and interest expense) are included in
the ''all other'' category. Total corporate administrative expenses for the
three and six months ended June 30, 2019 were $27.5 million and $57.2 million ,
respectively, and for the three and six months ended June 30, 2018 , corporate
administrative expenses were $21.2 million and $38.0 million , respectively. In
2020, the Company shut down its flowback operations in 2020 and disposed of the
assets. The comparability of the results of operations may have been impacted by
the Pioneer Pressure Pumping Acquisition resulting in additional eight fleets
deployed at the beginning of 2019.
Our hydraulic fracturing operating segment revenue approximated 95.6% and
95.8% of our pressure pumping revenue during the three and six months ended
June 30, 2019 , respectively. During the three and six months ended June 30,
2018 , our hydraulic fracturing operating segment revenue approximated 95.7% and
95.8% of our pressure pumping revenue, respectively.
The following table sets forth the results of operations for the periods
presented:
(in thousands, except for
percentages)
Three Months Ended June 30, Change
2019 2018 Variance %
Revenue $ 529,494 $ 459,888 $ 69,606 15.1 %
Cost of services (1) 386,218 351,888 34,330 9.8 %
General and administrative expense
(2) 27,889 14,178 13,711 96.7 %
Depreciation and amortization 35,482 21,276 14,206 66.8 %
Loss on disposal of assets 31,198 18,990 12,208 64.3 %
Interest expense 2,026 2,231 (205 ) (9.2 )%
Other expense 276 182 94 51.6 %
Income tax expense 10,272 12,052 (1,780 ) (14.8 )%
Net income $ 36,133 $ 39,091 $ (2,958 ) (7.6 )%
Adjusted EBITDA (3) $ 126,562 $ 95,968 $ 30,594 31.9 %
Adjusted EBITDA Margin (3) 23.9 % 20.9 % 3.0 % 14.4 %
Pressure pumping segment results of
operations:
Revenue $ 515,867 $ 445,805 $ 70,062 15.7 %
Cost of services $ 374,653 $ 341,890 $ 32,763 9.6 %
Adjusted EBITDA (3) $ 131,187 $ 97,818 $ 33,369 34.1 %
Adjusted EBITDA Margin (4) 25.4 % 21.9 % 3.5 % 16.0 %
(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".
(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.
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Three Months Ended
Revenues. Revenues increased 15.1%, or $69.6 million , to $529.5
million for the three months ended June 30, 2019 , as compared to $459.9 million
for the three months ended June 30, 2018 . The increase was primarily
attributable to the increase in hydraulic fracturing fleet size from 18.8 to
25.6 active fleets, and an increase in demand for our pressure pumping services
and customer activity, resulting in an increase in our customer base, during the
three months ended June 30, 2019 . Our pressure pumping segment revenues
increased 15.7%, or $70.1 million , for the three months ended June 30, 2019 , as
compared to the three months ended June 30, 2018 . Revenues from services other
than pressure pumping decreased 3.2%, or $0.5 million , to $13.6 million for the
three months ended June 30, 2019 as compared $14.1 million for the three months
ended June 30, 2018 . The decrease in revenues from services other than pressure
pumping was primarily attributable to the decrease in customer demand for our
flowback services during the three months ended June 30, 2019 and the disposal
of our surface drilling operations in August 2018 .
Cost of Services. Cost of services increased 9.8%, or $34.3 million , to
$386.2 million for the three months ended June 30, 2019 , as compared to $351.9
million during the three months ended June 30, 2018 . Cost of services in our
pressure pumping segment increased $32.8 million for the three months ended
June 30, 2019 , as compared to the three months ended June 30, 2018 . These
increases were primarily attributable to our increased active fleet count and
higher activity levels, resulting in an increase in employee headcount and as
well as our material and other direct costs. As a percentage of pressure pumping
segment revenues, pressure pumping cost of services decreased to 72.6% for the
three months ended June 30, 2019 , as compared to 76.7% for the three months
ended June 30, 2018 . The decrease in cost of services as a percentage of revenue
for our pressure pumping segment resulted from a favorable change in our cost
structure driven by our internal cost control measures, a decrease in the cost
of certain consumables and increase in customer self-sourcing sand and other
consumables, which resulted in higher realized Adjusted EBITDA margins during
the three months ended June 30, 2019 .
General and Administrative Expenses. General and administrative expenses
increased 96.7%, or $13.7 million , to $27.9 million for the three months ended
June 30, 2019 , as compared to $14.2 million for the three months ended June 30,
2018 . The net increase was primarily attributable to the increases in stock
compensation expense of $1.4 million , retention bonus expense of $1.7 million
associated with personnel who joined us as part of the Pioneer Pressure Pumping
Acquisition, professional fees paid to external consultants in connection with
the Expanded Audit Committee Review and advisory services of $6.5 million ,
insurance and office expenses of $1.9 million , dues/subscription expense of $1.0
million and a net decrease of $1.2 million in other remaining general and
administrative expenses.
Depreciation and Amortization. Depreciation and amortization increased
66.8%, or $14.2 million , to $35.5 million for the three months ended June 30,
2019 , as compared to $21.3 million for the three months ended June 30, 2018 . The
increase was primarily attributable to the increase in our fixed asset base as
of June 30, 2019 , resulting primarily from an increase in our pressure pumping
fleet capacity by 73.6% to 1,415,000 HHP in 2019.
Loss on Disposal of Assets. Loss on the disposal of assets increased
64.3%, or $12.2 million , to $31.2 million for the three months ended June 30,
2019 , as compared to $19.0 million for the three months ended June 30, 2018 . The
increase is attributable to the significant increase in our hydraulic fracturing
fleet size, greater service intensity of jobs completed, and higher maintenance
on certain of our pressure pumping equipment.
Interest Expense. Interest expense decreased 9.2%, or $0.2 million , to
$2.0 million for the three months ended June 30, 2019 , as compared to $2.2
million for the three months ended June 30, 2018 . The decrease in interest
expense was primarily attributable to a decrease in our average debt balance
during the three months ended June 30, 2019 compared to the three months ended
June 30, 2018 .
Other Expense. There was no significant change in other expense. Other
expense was $0.3 million for the three months ended June 30, 2019 , as compared
to $0.2 million for the three months ended June 30, 2018 .
Income Tax Expense. Total income tax expense was $10.3 million resulting
in an effective tax rate of 22.1% for the three months ended June 30, 2019 as
compared to $12.1 million and an effective tax rate of 23.6% for the three
months ended June 30, 2018 . The decrease in income tax expense during the three
months ended June 30, 2019 is primarily attributable to the decrease in pre-tax
book income during the three months ended June 30, 2019 as compared to the three
months ended June 30, 2018 .
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The following table sets forth the results of operations for the periods
presented:
(in thousands, except for percentages)
Six Months Ended June 30, Change
2019 2018 Variance %
Revenue $ 1,075,673 $ 845,107 $ 230,566 27.3 %
Cost of services (1) 767,741 650,010 117,731 18.1 %
General and administrative expense (2) 46,414 26,122 20,292 77.7 %
Depreciation and amortization 68,599 40,211 28,388 70.6 %
Loss on disposal of assets 50,425 26,655 23,770 89.2 %
Interest expense 3,928 3,492 436 12.5 %
Other expense 464 412 52 12.6 %
Income tax expense 32,164 22,406 9,758 43.6 %
Net income $ 105,938 $ 75,799 $ 30,139 39.8 %
Adjusted EBITDA (3) $ 276,837 $ 172,712 $ 104,125 60.3 %
Adjusted EBITDA Margin (3) 25.7 % 20.4 % 5.3 % 26.0 %
Pressure pumping segment results of
operations:
Revenue $ 1,047,931 $ 820,850 $ 227,081 27.7 %
Cost of services $ 745,757 $ 632,360 $ 113,397 17.9 %
Adjusted EBITDA (3) $ 282,228 $ 176,881 $ 105,347 59.6 %
Adjusted EBITDA Margin (4) 26.9 % 21.5 % 5.4 % 25.1 %
(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".
(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.
Six Months Ended
Revenues. Revenues increased 27.3%, or $230.6 million , to $1,075.7
million for the six months ended June 30, 2019 , as compared to $845.1 million
for the six months ended June 30, 2018 . The increase was primarily attributable
to the increase in hydraulic fracturing fleet size from 18.1 to 26.3 active
fleets, demand for our pressure pumping services and customer activity,
resulting in an increase in our customer base, during the six months ended
June 30, 2019 . Our pressure pumping segment revenues increased 27.7%, or $227.1
million , for the six months ended June 30, 2019 , as compared to the six months
ended June 30, 2018 . Revenues from services other than pressure pumping
increased 14.4%, or $3.5 million , for the six months ended June 30, 2019 as
compared to the six months ended June 30, 2018 . The increase in revenues from
services other than pressure pumping was primarily attributable to the increase
in our coiled tubing units and customer demand for coil tubing services.
Cost of Services. Cost of services increased 18.1%, or $117.7 million , to
$767.7 million for the six months ended June 30, 2019 , as compared to $650.0
million during the six months ended June 30, 2018 . Cost of services in our
pressure pumping segment increased $113.4 million for the six months ended
June 30, 2019 , as compared to the six months ended June 30, 2018 . The increase
was primarily attributable to higher activity levels in our pressure pumping
operations, hydraulic fracturing fleet size, and an increase in personnel
headcount following the increased activity levels. As a percentage of pressure
pumping segment revenues, pressure pumping cost of services decreased to 71.2%
for the six months ended June 30, 2019 , as compared to 77.0% for the six months
ended June 30, 2018 . The decrease in cost of services as a percentage of revenue
for our pressure pumping segment resulted from a favorable change in our cost
structure driven by our internal cost control measures and a decrease in the
cost of certain consumables and increase in customer self-sourcing sand and
other consumables, which resulted in higher realized Adjusted EBITDA margins
during the six months ended June 30, 2019 .
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General and Administrative Expenses. General and administrative expenses
increased 77.7% or $20.3 million to $46.4 million for the six months ended
June 30, 2019 , as compared to $26.1 million for the six months ended June 30,
2018 . The net increase was primarily attributable to increases in stock
compensation expense of $2.5 million , retention bonus expense of $3.6 million
associated with personnel who joined us as part of the Pioneer Pressure Pumping
Acquisition, professional fees paid to external consultants in connection with
the Expanded Audit Committee Review and advisory services of $6.5 million ,
office expense of $1.6 million , insurance expense of $2.6 million ,
dues/subscription of $1.1 million and net aggregate increase in other remaining
general and administrative expenses of $2.3 million .
Depreciation and Amortization. Depreciation and amortization increased
70.6%, or $28.4 million , to $68.6 million for the six months ended June 30,
2019 , as compared to $40.2 million for the six months ended June 30, 2018 . The
increase was primarily attributable to the increase in our fixed asset base as
of June 30, 2019 , resulting primarily from an increase in our pressure pumping
fleet capacity by 73.6% to 1,415,000 HHP in 2019.
Loss on Disposal of Assets. Loss on the disposal of assets increased
89.2%, or $23.8 million , to $50.4 million for the six months ended June 30,
2019 , as compared to $26.7 million for the six months ended June 30, 2018 . The
increase is attributable to the significant increase in hydraulic fracturing
fleet size, greater service intensity of jobs completed and higher activity
levels on certain of our pressure pumping equipment.
Interest Expense. Interest expense increased 12.5%, or $0.4 million , to
$3.9 million for the six months ended June 30, 2019 , as compared to $3.5 million
for the six months ended June 30, 2018 . The increase in interest expense was
primarily attributable to an increase in our average debt balance during the six
months ended June 30, 2019 compared to the six months ended June 30, 2018 .
Other Expense. There was no significant change in other expense. Other
expense was $0.5 million for the six months ended June 30, 2019 , as compared to
$0.4 million for the six months ended June 30, 2018 .
Income Tax Expense. Total income tax expense was $32.2 million resulting
in an effective tax rate of 23.3% for the six months ended June 30, 2019 as
compared to $22.4 million and an effective tax rate of 22.8% for the six months
ended June 30, 2018 . The increase in income tax expense during the six months
ended June 30, 2019 is primarily attributable to the increase in pre-tax book
income during six months ended June 30, 2019 as compared to the six months ended
June 30, 2018 .
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Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii)
operating cash flows and (iii) borrowings under our revolving credit facility
("ABL Credit Facility"). Our primary uses of cash will be to continue to fund
our operations, support growth opportunities and satisfy debt payments. 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.
With the current depressed oil and gas market conditions, we believe our
remaining monthly availability under our ABL Credit facility will be adversely
impacted by the expected decline in our customers' activity.
As of June 30, 2019 , our borrowings under our ABL Credit Facility was
$150.0 million and our total liquidity was $146.5 million , consisting of cash
and cash equivalents of $36.3 million and $110.2 million of availability under
our ABL Credit Facility.
As of June 19, 2020 , we had no borrowings under our ABL Credit Facility and
our total liquidity was approximately $57.4 million , consisting of cash and cash
equivalents of $42.2 million and $15.2 million of availability under our ABL
Credit Facility.
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 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.
The global public health crisis associated with the COVID-19 pandemic has
and is anticipated to continue to have an adverse effect on global economic
activity for the immediate future and has resulted in travel restrictions,
business closures and the institution of quarantining and other restrictions on
movement in many communities. The slowdown in global economic activity
attributable to COVID-19 has resulted in a dramatic decline in the demand for
energy which directly impacts our industry and the Company. In addition, global
crude oil prices experienced a collapse starting in early March 2020 . As a
result of these developments, the Company expects a material adverse impact on
the oil field services we provide and our revenue, results of operations and
cash flows. These situations are rapidly changing and additional impacts to the
business may arise that we are not aware of currently and the depressed oil and
gas industry may take a longer time to recover thereby significantly impacting
on revenue, results of operations and cash flows for a longer period of time.
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 June 30, 2019 was approximately $261.8 million and was
approximately $16.8 million as of June 19, 2020 . The ABL Credit Facility
includes a Springing Fixed Charge Coverage Ratio to apply when excess
availability is less than the greater of (i)10%of the lesser of the facility
size or the Borrowing Base or (ii) $22.5 million . Under this facility we are
required to comply, subject to certain exceptions and materiality qualifiers,
with certain customary affirmative and negative covenants, including, but not
limited to, covenants pertaining to our ability to incur liens, indebtedness,
changes in the nature of our business, mergers and other fundamental changes,
disposal of assets, investments and restricted payments, amendments to our
organizational documents or accounting policies, prepayments of certain debt,
dividends, transactions with affiliates, and certain other activities.
Borrowings under the ABL Credit Facility are secured by a first priority lien
and security interest in substantially all assets of the Company.
Borrowings under the ABL Credit Facility accrue interest based on a
three-tier pricing grid tied to availability, and we may elect for loans to be
based on either LIBOR or base rate, plus the applicable margin, which ranges
from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with
a LIBOR floor of zero. The weighted average interest rate for our ABL Credit
Facility for the six months ended June 30, 2019 was 4.7%.
In March 2020 , we obtained a waiver from our lenders under the ABL Credit
Facility to extend the time period for us to provide our lenders the Company's
audited financial statements for the year ended December 31, 2019 to July 31,
2020 .
In July 2017 , the United Kingdom's Financial Conduct Authority , which
regulates LIBOR, announced that it intend 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 2021when 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.
As of June 30, 2019 , we had 108,000 HHP of DuraStim® hydraulic pumps on
order for delivery between 2019 and 2020, with an option to purchase an
additional 108,000 HHP of DuraStim® hydraulic pumps. We expect the initial
108,000 HHP of fully deployable DuraStim® fleets to cost an aggregate of
approximately $179.1 million (including auxiliary and mixing equipment and power
turbines), of which approximately $96.7 million has been spent as of June 30,
2019 and the remaining
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approximately $82.4 million is expected to be spent in the second half of 2019
and 2020. We expect to fund these fleet purchases with a combination of (i) cash
in hand and (ii) borrowings under our ABL Credit Facility.
Future Sources and Use of Cash and Contractual Obligations
In the normal course of business, we enter into various contractual
obligations that impact on our future liquidity. The table below contains our
known material contractual obligations as of June 30, 2019 .
($ in thousands) Total Less than 1 year 1 - 3 years 4- 5 years
ABL Credit Facility (1) $ 150,000 $ - $ - $ 150,000
Operating leases(2) 1,969 259 1,063 647
Finance leases (2) 3,022 3,022 - -
Capital expenditures(3) 48,916 48,916 - -
Total $ 203,907 $ 52,197 $ 1,063 $ 150,647 (1) Exclusive of future commitment fees, amortization of deferred financing
costs, interest expense or other fees on our revolving credit facility
because obligations thereunder are floating rate instruments and we cannot
determine with accuracy the timing of future loan advances, repayments or
future interest rates to be charged.
(2) Finance and Operating leases include agreements for various office locations,
excluding short-term leases (see Notes (9) Leases and (10) Commitments and
Contingencies in the financial statements for additional disclosures).
(3) Capital expenditures relate to the contractual expenditures (see Note 10
Commitments and Contingencies). Amounts reflected in the table above do not
include any potential capital expenditures associated with the 108,000 HHP of
DuraStim® hydraulic pumps (or associated auxiliary and mixing equipment and
power equipment) that we have an option to purchase through
We have option agreements with our equipment manufacturer to purchase
additional DuraStim® hydraulic fracturing pumps of approximately 108,000 HHP
through April 30, 2021 . We believe the cost to acquire the DuraStim® pumps will
be comparable to our previously purchased DuraStim® pumps. In the current
economic environment it is not probable we would exercise these options before
they expire. However, if we decide to exercise our purchase options, it will
represent an increase in our growth capital expenditures and we will expect to
finance that purchase from our then existing cash on hand, cash flows from
operation or borrowings under our ABL Credit Facility.
We have repaid all our borrowings, as of
The Company enters into purchase agreements with the Sand suppliers to
secure supply of sand as part of its normal course of business. The agreements
with the Sand suppliers require that the Company purchase a minimum volume of
sand, constituting substantially all of its sand requirements, from the Sand
suppliers, otherwise certain penalties may be charged. Under certain of the
purchase agreements, a shortfall fee applies if the Company purchases less than
the minimum volume of sand. 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. Under one of the purchase
agreements, the Company is obligated to purchase a specified percentage of its
overall sand requirements, or it must pay the supplier the difference between
the purchase price of the minimum volumes under the purchase agreement and the
purchase price of the volumes actually purchased. Our minimum volume commitments
under the purchase agreements are either based on a percentage of our total
usage or fixed minimum quantity. Our agreements with the Sand suppliers expire
at different times prior to April 30, 2022 .
In the normal course of business, we enter into various contractual
obligations and routine growth and maintenance capital expenditures that impact
on our future liquidity. There were no other known material contractual
obligations and estimate for future capital expenditures as of
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--------------------------------------------------------------------------------Cash and Cash Flows
The following table sets forth the historical cash flows for the six
months ended
Six Months Ended June 30,
($ in thousands) 2019 2018
Net cash provided by (used in):
Operating activities $ 150,851 $ 124,442
Investing activities $ (324,334 ) $ (149,909 )
Financing activities $ 77,062 $ 28,621 Cash Flows From Operating Activities
Net cash provided by operating activities was $150.9 million for the six
months ended June 30, 2019 , compared to net cash provided by operating
activities of $124.4 million for the six months ended June 30, 2018 . The net
increase of $26.4 million was primarily due to the expansion of our operations
following the acquisition of Pioneer Pressure Pumping Assets as well as the
associated increase in revenue and operating profits from the expansion of
operations, and the timing of our receivable from customers and payment to
vendors. During the six months ended June 30, 2019 , our average active fleet
count was approximately 26 fleets compared to 18 fleets during the six months
ended June 30, 2018 . Our increase in fleet size has resulted in our ability to
service more customer wells and thus increased operating cash flows.
Cash Flows From Investing Activities
Net cash used in investing activities increased to $324.3 million for the
six months ended June 30, 2019 , from $149.9 million for the six months ended
June 30, 2018 . The increase was primarily attributable to the cash payment of
approximately $110.0 million for 510,000 HHP, 4 coiled tubing units and
maintenance yard acquired in the Pioneer Pressure Pumping Acquisition. In
addition, in the six months ended June 30, 2019 , we made cash deposits of $102.9
million with our equipment manufacturers for 108,000 HHP of new-build DuraStim®
hydraulic fracturing pumps and turbines which are expected to be delivered at
different times in 2019 and 2020. Included in our cash deposits with our
equipment manufacturers was an option fee of $6.1 million related to our option
to acquire 108,000 HHP of additional DuraStim® pumps through the end of April
2021 . The option fee will be equally applied towards the purchase price of each
additional DuraStim® fleet ordered. We also paid approximately $68.2 million for
maintenance capital expenditures and $42.9 million on other growth initiatives
during the six months ended June 30, 2019 .
Cash Flows From Financing Activities
Net cash provided by financing activities was $77.1 million for the six
months ended June 30, 2019 , and $28.6 million for the six months ended June 30,
2018 . The net increase in cash provided by financing activities during the six
months ended June 30, 2019 was primarily driven by the increase in net
borrowings under our ABL Credit Facility, compared to six months ended June 30,
2018 . Our net cash provided from financing activities during the six months
ended June 30, 2019 , was primarily driven by additional borrowings under our ABL
Credit Facility of $90.0 million , proceeds from equity awards of $1.1 million ,
and offset by our use of cash for repayment of borrowings of $10.0 million and
insurance financing of $3.9 million . Our net cash provided from financing
activities during the six months ended June 30, 2018 was primarily driven by our
borrowings of $57.4 million , and offset by our use of cash for repayment of
borrowings of $25.2 million , insurance financing of $3.2 million and debt
issuance cost of $0.4 million .
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of
There have been no material changes during the six months ended June 30,
2019 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 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.
Impairments
In the fourth quarter of 2019, management determined that the demand for
vertical rigs and flowback services in the Permian Basin continued to be
depressed. The Company's (i) vertical drilling rigs were not more likely than
not to be utilized in
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the foreseeable future and (ii) flowback assets were having a deterioration in
utilization. As such we expect to record impairment charges of approximately
$3.4 million in the fourth quarter of 2019.
During the first quarter of 2020, management determined the reductions in
commodity prices driven by the potential impact of the novel COVID-19 virus and
global supply and demand dynamics coupled with the sustained decrease in the
Company's share price were triggering events for goodwill and asset impairment.
As a result of the triggering events, we performed an interim goodwill
impairment test on the hydraulic fracturing reporting unit and a recoverability
tests on each of the assets groups. As a result, we expect to recognize
impairments and charges in the first quarter of 2020 as follows:
• goodwill impairment of approximately
• drilling asset group impairment of approximately$1.1 million as a result of our recoverability tests; and • write-off of$6.1 million of deposits related to options to purchase additional DuraStim® equipment for which options expire at various times through the end ofApril 2021 as it is not probable we would exercise our options due to the events describe above. If the depressed oil prices and the current economic conditions remain for a longer period of time, actual results may differ from estimates and future assumptions may change resulting in additional impairment charges in the future. 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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