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 June 30, 2021 , was 1,423,000 HHP, which was
comprised of 50,000 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® 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 wellsite. With the industry transition to lower emissions
equipment and simultaneous hydraulic 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 backup HHP at the wellsites based on our customers' operational needs or
as we retire and replace our conventional Tier II equipment.
In 2019, we entered into a purchase commitment for 108,000 HHP of DuraStim®
electric powered hydraulic fracturing equipment. During the second quarter of
2021, we increased the scope of our DuraStim® equipment field trials by
increasing the number of DuraStim® pumps deployed to our customer's wellsites.
As we continue with our field trials, the ideal 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 had set a goal to fully
commercialize its first DuraStim® fleet in the second half of 2021, subject to
the completion of successful testing. Largely due to supply chain disruptions
impacting the continuing testing process, the timing for the Company's ultimate
decisions regarding DuraStim® commercialization may be extended 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 two
gas turbines, that could 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 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 requirements, and the continuing depressed pricing experienced by
the service 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, reliability, ability to manage
complex logistics challenges, 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
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Basin specific operating conditions and the region's increasingly high-intensity well completions (including simultaneous 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 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 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. 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 . In 2021, 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 significant recovery in the
energy industry and overall economic activities from its lowest point in 2020.
However, the demand for crude oil increased rapidly during the first half of
2021 and is expected to continue to increase, but there has been no significant
increase in oil and gas production in the United States , which has led to WTI
crude oil prices increasing to approximately $72 as of July 28, 2021 . The oil
and gas industry has not fully recovered as evidenced by continued depressed
pricing for most oilfield services, including our services, and shortages of
skilled labor force in the Permian Basin . However, 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 . Accordingly, the Permian Basin
rig count increased significantly from approximately 124 at the beginning of
August 2020 to approximately 243 at the end of July 2021 , according to Baker
Hughes .
Government regulations and investors are demanding the oil and gas industry
transition to a lower emissions operating environment, including the upstream
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.
The Permian Basin rig count increase, WTI crude oil price increase and
costs 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.
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--------------------------------------------------------------------------------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 and one-time professional fees on legal settlements. 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 income (loss) to Adjusted EBITDA (in thousands):
Three
Months Ended
Pressure Pumping All Other Total
Net loss $ (809) $ (7,702) $ (8,511)
Depreciation and amortization 32,256 987 33,243
Interest expense - 159 159
Income tax benefit - (3,697) (3,697)
Loss (gain) on disposal of assets 15,379 (354) 15,025
Stock-based compensation - 2,909 2,909
Other expense - 302 302
Other general and administrative expense(1) - (3,737) (3,737)
Adjusted EBITDA $ 46,826 $ (11,133) $ 35,693
Three
Months Ended
Pressure Pumping All Other Total
Net loss $ (13,528) $ (12,392) $ (25,920)
Depreciation and amortization 38,910 1,263 40,173
Interest expense - 791 791
Income tax benefit - (6,460) (6,460)
Loss on disposal of assets 8,587 147 8,734
Stock-based compensation - 2,962 2,962
Other expense - 267 267
Other general and administrative expense(1) - 4,802 4,802
Retention bonus and severance expense 61 - 61
Adjusted EBITDA $ 34,030 $ (8,620) $ 25,410
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Six
Months Ended
Pressure Pumping All Other Total
Net loss $ (14,484) $ (14,402) $ (28,886)
Depreciation and amortization 64,770 1,951 66,721
Interest expense - 335 335
Income tax benefit - (10,360) (10,360)
Loss (gain) on disposal of assets 28,411 (335) 28,076
Stock-based compensation - 5,396 5,396
Other income - (1,487) (1,487)
Other general and administrative expense (1) - (4,698) (4,698)
Retention bonus and severance expense - 612 612
Adjusted EBITDA $ 78,697 $ (22,988) $ 55,709
Six
Months Ended
Pressure Pumping All Other Total
Net loss $ (9,220) $ (24,504) $ (33,724)
Depreciation and amortization 77,879 2,498 80,377
Impairment expense 15,559 1,095 16,654
Interest expense 1 2,071 2,072
Income tax benefit - (7,370) (7,370)
Loss on disposal of assets 28,402 186 28,588
Stock-based compensation - 3,433 3,433
Other expense - 271 271
Other general and administrative expense (1) - 9,937 9,937
Retention bonus and severance expense 75 21 96
Adjusted EBITDA $ 112,696 $ (12,362) $ 100,334
(1)Other general and administrative expense, (net of reimbursement from
insurance carriers) relates to nonrecurring professional fees paid to external
consultants in connection with the Company's pending SEC investigation and
shareholder litigation, net of insurance recoveries. During the three and six
months ended June 30, 2021 , we received reimbursement of approximately
$5.1 million and $6.7 million , respectively, from our insurance carriers in
connection with the SEC investigation and shareholder litigation.
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--------------------------------------------------------------------------------Results of Operations
We conducted 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),
other (income) and expense and interest expense) are included in the "all other"
category. Total corporate administrative expense for the three and six months
ended June 30, 2021 was $6.5 million and $11.6 million , respectively. The
corporate administrative expense for the three and six months ended June 30,
2020 was $10.6 million and $20.9 million , respectively.
Our hydraulic fracturing operating segment revenue approximated 93.7% and
93.5% of our pressure pumping revenue during the three and six months ended
June 30, 2021 , respectively. During the three and six months ended June 30,
2020 , our hydraulic fracturing operating segment revenue approximated 89.7% and
93.7% 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 Change
June 30, Increase (Decrease)
2021 2020 $ %
Revenue $ 216,887 $ 106,109 $ 110,778 104.4 %
Less (Add):
Cost of services (1) 162,837 68,193 94,644 138.8 %
General and administrative expense (2) 17,529 20,331 (2,802) (13.8) %
Depreciation and amortization 33,243 40,173 (6,930) (17.3) %
Loss on disposal of assets 15,025 8,734 6,291 72.0 %
Interest expense 159 791 (632) (79.9) %
Other expense 302 267 35 13.1 %
Income tax benefit (3,697) (6,460) (2,763) (42.8) %
Net loss $ (8,511) $ (25,920) $ (17,409) (67.2) %
Adjusted EBITDA (3) $ 35,693 $ 25,410 $ 10,283 40.5 %
Adjusted EBITDA Margin (3) 16.5 % 23.9 % (7.4) % (31.0) %
Pressure pumping segment results of
operations:
Revenue $ 213,461 $ 103,815 $ 109,646 105.6 %
Cost of services $ 159,490 $ 65,991 $ 93,499 141.7 %
Adjusted EBITDA (3) $ 46,826 $ 34,030 $ 12,796 37.6 %
Adjusted EBITDA Margin (4) 21.9 % 32.8 % (10.9) % (33.2) %
(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 $1.0 million and $32.6 million for the three months ended June 30,
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.
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Three Months Ended
Revenues. Revenues increased 104.4%, or $110.8 million , to $216.9
million during the three months ended June 30, 2021 , as compared to $106.1
million during the three months ended June 30, 2020 . Our pressure pumping
segment revenues increased 105.6%, or $109.6 million , for the three months ended
June 30, 2021 , as compared to the three months ended June 30, 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 a significant
increase in our average effectively utilized fleet count to approximately 13.1
active fleets during the three months ended June 30, 2021 from approximately 4.0
active fleets for the three months ended June 30, 2020 . Included in our revenue
for the three months ended June 30, 2021 and 2020 was revenue generated from
idle fees charged to our customer of approximately $1.0 million and $32.6
million , respectively.
Revenues from services other than pressure pumping increased 49.3%, or $1.1
million , to $3.4 million for the three months ended June 30, 2021 , as compared
to $2.3 million for the three months ended June 30, 2020 . The increase in
revenue from services other than pressure pumping was primarily attributable to
the increase in utilization experienced by 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 138.8%, or $94.6 million , to
$162.8 million for the three months ended June 30, 2021 , as compared to $68.2
million during the three months ended June 30, 2020 . Cost of services in our
pressure pumping segment increased $93.5 million for the three months ended
June 30, 2021 , as compared to the three months ended June 30, 2020 . These
increases were primarily attributable to the significantly increased activity
levels resulting from the increased demand for our services 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 was 74.7% for the three months ended June 30,
2021 , as compared to 63.6% for the three months ended June 30, 2020 . Our revenue
during the three months ended June 30, 2020 , included significant idle fee
revenue. Excluding idle fees revenue of $1.0 million and $32.6 million recorded
during the three months ended June 30, 2021 and 2020, respectively, our pressure
pumping cost of services as a percentage of pressure pumping revenues decreased
to 75.1% during the three months ended June 30, 2021 , as compared to 92.7% for
the three months ended June 30, 2020 . The decrease was a result of increased
customer activity levels, which is consistent with our fleet utilization.
General and Administrative Expenses. General and administrative expenses
decreased 13.8%, or $2.8 million , to $17.5 million for the three months ended
June 30, 2021 , as compared to $20.3 million for the three months ended June 30,
2020 . The net decrease was primarily attributable to a decrease in (i)
nonrecurring advisory and professional fees of $8.5 million paid to external
consultants in connection with the Company's pending SEC investigation and
shareholder litigation, (ii) legal and professional fees of $2.6 million ,
partially offset by net increases of $3.8 million in payroll expenses and 4.5
million in other remaining general and administrative expenses.
Depreciation and Amortization. Depreciation and amortization decreased
17.3%, or $6.9 million , to $33.2 million for the three months ended June 30,
2021 , as compared to $40.2 million for the three months ended June 30, 2020 . The
decrease was primarily attributable to the decrease in our fixed asset base,
partly attributable to the impairment of certain fixed assets in 2020.
Loss on Disposal of Assets. Loss on the disposal of assets increased
72.0%, or $6.3 million , to $15.0 million for the three months ended June 30,
2021 , as compared to $8.7 million for the three months ended June 30, 2020 . The
increase was primarily attributable to the significant increase in utilization
resulting in an increase in the operational intensity on our equipment. 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 79.9%, or $0.6 million , to
$0.2 million for the three months ended June 30, 2021 , as compared to $0.8
million for the three months ended June 30, 2020 . The decrease in interest
expense was primarily attributable to the decrease in our average debt balance
during the three months ended June 30, 2021 compared to the three months ended
June 30, 2020 . During the three months ended June 30, 2021 , the Company had a
zero debt balance, and the interest expense in the three months ended June 30,
2021 , relates to the amortization of our capitalized loan origination cost.
Other Expense. There was no significant change in other expense. Other
expense was $0.3 million for the three months ended June 30, 2021 , as compared
to $0.3 million for the three months ended June 30, 2020 . A significant portion
of our other expense consists of our lender's commitment fees.
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Income Taxes. Total income tax benefit was $3.7 million resulting in an
effective tax rate of 30.3% for the three months ended June 30, 2021 , as
compared to income tax expense of $6.5 million or an effective tax rate of 20.0%
for the three months ended June 30, 2020 . The income tax benefit recorded in the
three months ended June 30, 2021 is primarily attributable to the Company
projecting a pre-tax loss in 2021 as compared to pre-tax income in 2020.
Furthermore, the change in the effective tax rate from 20.0% to 30.3% in the
three months ended June 30, 2021 was primarily attributable to nondeductible
expenses and discrete items such as stock compensation expense reducing the
benefit recorded for the pre-tax loss.
The following table sets forth the results of operations for the periods
presented:
(in thousands, except for percentages) Six Months Ended Change
June 30, Increase (Decrease)
2021 2020 $ %
Revenue $ 378,345 $ 501,178 $ (122,833) (24.5) %
Less (Add):
Cost of services (1) 286,215 369,041 (82,826) (22.4) %
General and administrative expense (2) 37,731 45,269 (7,538) (16.7) %
Depreciation and amortization 66,721 80,377 (13,656) (17.0) %
Impairment expense - 16,654 (16,654) (100.0) %
Loss on disposal of assets 28,076 28,588 (512) (1.8) %
Interest expense 335 2,072 (1,737) (83.8) %
Other (income)/expense (1,487) 271 1,758 (648.7) %
Income tax benefit (10,360) (7,370) 2,990 40.6 %
Net loss $ (28,886) $ (33,724) $ (4,838) (14.3) %
Adjusted EBITDA (3) $ 55,709 $ 100,334 $ (44,625) (44.5) %
Adjusted EBITDA Margin (3) 14.7 % 20.0 % (5.3) % (26.5) %
Pressure pumping segment results of
operations:
Revenue $ 371,652 $ 490,735 $ (119,083) (24.3) %
Cost of services $ 279,258 $ 360,215 $ (80,957) (22.5) %
Adjusted EBITDA (3) $ 78,697 $ 112,696 $ (33,999) (30.2) %
Adjusted EBITDA Margin (4) 21.2 % 23.0 % (1.8) % (7.8) %
(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 $5.3 million and $34.1 million for the six months ended June 30,
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.
Six Months Ended June 30, 2021 Compared to the Six Months Ended June 30, 2020
Revenues. Revenues decreased 24.5%, or $122.8 million , to $378.3 million
during the six months ended June 30, 2021 , as compared to $501.2 million during
the six months ended June 30, 2020 . Our pressure pumping segment revenues
decreased 24.3%, or $119.1 million , for the six months ended June 30, 2021 , as
compared to the six months ended June 30, 2020 . The decreases were primarily
attributable to the significant pricing discounts we provided our customers
beginning April 2020 , and in part due to substantially all of our customers
directly sourcing certain consumables like sand, chemical, and diesel. Our
average effectively utilized fleet count during the six months ended June 30,
2021 , was approximately 11.7 active fleets, compared to 11.1 during the six
months ended June 30, 2020 . Included in our revenue for the six months ended
June 30, 2021 and 2020 was revenue generated from idle fees charged to our
customer of approximately $5.3 million and $34.1 million , respectively.
Revenues from services other than pressure pumping decreased 35.9%, or $3.8
million , to $6.7 million for the six months ended June 30, 2021 , as compared to
$10.4 million for the six months ended June 30, 2020 . The decrease in revenues
from services other than pressure pumping was primarily attributable to the
disposal of our flowback operations in March 2020 .
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Cost of Services. Cost of services decreased 22.4%, or $82.8 million , to
$286.2 million for the six months ended June 30, 2021 , as compared to $369.0
million during the six months ended June 30, 2020 . Cost of services in our
pressure pumping segment decreased $81.0 million for the six months ended June
30, 2021 , as compared to the six months ended June 30, 2020 . These decreases
were primarily attributable to the significant reduction in the consumables
(like sand, chemical and diesel) we sourced for customers and also our cost
optimization strategies following the depressed oil prices and economic slowdown
caused by the COVID-19 pandemic. As a percentage of pressure pumping segment
revenues (including idle fees), pressure pumping cost of services increased to
75.1% for the six months ended June 30, 2021 , as compared to 73.4% for the six
months ended June 30, 2020 . The increase in our cost of services percentage was
primarily attributable to pricing pressure on our services resulting in customer
discounts, partially offset by the idle fees revenue. Excluding idle fees
revenue of $5.3 million and $34.1 million recorded during the six months ended
June 30, 2021 and 2020, respectively, our pressure pumping cost of services as a
percentage of pressure pumping revenues decreased to 76.2% during the six months
ended June 30, 2021 , as compared to 78.9% for the six months ended June 30,
2020 . The decrease was a result of increased operational efficiencies and
reduction in certain consumables provided to customers.
General and Administrative Expenses. General and administrative expenses
decreased 16.7%, or $7.5 million , to $37.7 million for the six months ended June
30, 2021 , as compared to $45.3 million for the six months ended June 30, 2020 .
The net decrease was primarily attributable to a decrease in (i) nonrecurring
advisory and professional fees of $14.6 million paid to external consultants in
connection with the Company's pending SEC investigation and shareholder
litigation, (ii) legal and professional fees of approximately $2.7 million ,
which was partially offset by a net increase of approximately $9.0 million paid
in payroll expenses, and $0.8 million in other remaining general and
administrative expenses.
Depreciation and Amortization. Depreciation and amortization decreased
17.0%, or $13.7 million , to $66.7 million for the six months ended June 30,
2021 , as compared to $80.4 million for the six months ended June 30, 2020 . The
decrease was primarily attributable to the overall decrease in our fixed asset
base in 2020, partly attributable to the impairment of certain fixed assets in
2020.
Impairment Expense. There was no impairment expense during the six months
ended June 30, 2021 . During the six months ended June 30, 2020 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 $16.7 million , of which $9.4 million relates to goodwill impairment
and $7.2 million relates to property and equipment impairment.
Loss on Disposal of Assets. Loss on the disposal of assets was relatively
flat with a slight decrease of 1.8%, or $0.5 million , to $28.1 million for the
six months ended June 30, 2021 , as compared to $28.6 million for six months
ended June 30, 2020 .
Interest Expense. Interest expense decreased 83.8%, or $1.7 million , to
$0.3 million for the six months ended June 30, 2021 , as compared to $2.1 million
for the six months ended June 30, 2020 . The decrease in interest expense was
primarily attributable to the decrease in our average debt balance during the
six months ended June 30, 2021 compared to the six months ended June 30, 2020 .
Other (Income)/Expense. Other income increased to approximately $1.5
million for the six months ended June 30, 2021 , as compared to $0.3 million in
expense for the six months ended June 30, 2020 . 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 six months ended June 30,
2021 , as compared to the six months ended June 30, 2020 .
Income Taxes. Total income tax benefit was $10.4 million resulting in an
effective tax rate of 26.4% for the six months ended June 30, 2021 , as compared
to income tax expense of $7.4 million or an effective tax rate of 17.9% for the
six months ended June 30, 2020 . The income tax benefit recorded in the six
months ended June 30, 2021 is primarily attributable to the Company projecting a
pre-tax loss in 2021 as compared to pre-tax income in 2020. Furthermore, the
change in the effective tax rate from 17.9% to 26.4% in the six months ended
June 30, 2021 was primarily attributable to nondeductible expenses and discrete
items such as stock compensation expense reducing the benefit recorded for the
pre-tax loss.
-27---------------------------------------------------------------------------------
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 June 30, 2021 , we had no borrowings under our ABL Credit Facility,
and our total liquidity was approximately $140.8 million , consisting of cash and
cash equivalents of $72.7 million and $68.1 million of availability under our
ABL Credit Facility.
As of July 28, 2021 , our total liquidity was approximately $140.0 million ,
consisting of cash and cash equivalents of $70.8 million and $69.2 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
resulting from the reduction in the COVID-19 infection rate following 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 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.
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, 2021 was approximately $71.8 million and was
approximately $72.9 million as of July 28, 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 six months ended June 30, 2021 .
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, although our ABL Credit
Facility agreement allows us to elect an alternative rate (base rate) to accrue
interest.
-28---------------------------------------------------------------------------------
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 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. Currently, because of ongoing testing and
commercialization efforts, we cannot reasonably determine whether or not we will
exercise these options before they expire.
In the normal course of business, we enter into various contractual
obligations and incur expenses in connection with routine growth and maintenance
capital expenditures that impact our future liquidity. There were no other known
future material contractual obligations as of June 30, 2021 .
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) 2021 2020
Net cash provided by operating activities
Net cash used in investing activities $ (50,920)
Net cash used in financing activities $ (6,631) Cash Flows From Operating Activities
Net cash provided by operating activities was $61.5 million for the six
months ended June 30, 2021 , compared to net cash provided by operating
activities of $96.9 million for the six months ended June 30, 2020 . The net
decrease of $35.4 million was primarily due to decreased profitability and the
timing of collections of our receivables from customers and payments to vendors.
Our effectively utilized fleet count was relatively flat with a slight increase
to approximately 11.7 active fleets during the six months ended June 30, 2021
from approximately 11.1 active fleets for the six months ended June 30, 2020 .
Cash Flows From Investing Activities
Net cash used in investing activities decreased to $50.9 million for the
six months ended June 30, 2021 , from $78.0 million for the six months ended June
30, 2020 . The decrease was primarily attributable to the lower maintenance
capital expenditures driven primarily by equipment redundancies.
Cash Flows From Financing Activities
Net cash used in financing activities was $6.6 million for the six months
ended June 30, 2021 , and net cash provided by financing activities was $130.6
million for the six months ended June 30, 2020 . The net decrease in cash from
financing activities during the six months ended June 30, 2021 was primarily
driven by no repayments of borrowings under our ABL Credit Facility, compared to
repayment of borrowings under our ABL Credit Facility of $130 million during the
six months ended June 30, 2020 .
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of
-29-
--------------------------------------------------------------------------------Critical Accounting Policies and Estimates
There have been no material changes during the six months ended June 30,
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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