PROPETRO HOLDING CORP. You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Annual Report. Some of the information contained in this discussion and analysis or set forth elsewhere in this Annual Report, including information with respect to our plans and strategy for our business and related financing, includes forwardlooking statements that involve risks and uncertainties. You should read the "Risk Factors" section of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forwardlooking statements contained in the following discussion and analysis. Basis of Presentation This discussion of our results of operations omits our results of operations for the year endedDecember 31, 2017 and the comparison of our results of operations for the years endedDecember 31, 2018 and 2017, which may be found in our Annual Report on Form 10-K for the year endedDecember 31, 2018 , filed with theSEC onMarch 1, 2019 . Unless otherwise indicated, references in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" to "ProPetro Holding Corp. ," "the Company," "we," "our," "us" or like terms refer toProPetro Holding Corp. and its subsidiary. Overview Our Business We are a growthoriented, Midland, Texasbased oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production, or E&P, of North American unconventional oil and natural gas resources. Our operations are primarily focused in thePermian Basin , where we have cultivated longstanding customer relationships with some of the region's most active and wellcapitalized E&P companies.The Permian Basin is widely regarded as one of the most prolific oilproducing areas inthe United States , and we believe we are one of the leading providers of hydraulic fracturing services in the region by hydraulic horsepower. Changes to our customers' well design, shale formations, operating conditions and new technology have resulted in continuous changes to the number of pumps, 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. As such, our total available HHP atDecember 31, 2019 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. Our first DuraStim® hydraulic fracturing pumps of 54,000 HHP was delivered inDecember 2019 and deployed to a customer inJanuary 2020 . We expect that the additional DuraStim® hydraulic fracturing pumps of 54,000 HHP will be delivered during 2020. We also have an option to purchase up to an additional 108,000 HHP of DuraStim® hydraulic fracturing pumps in the future throughApril 30, 2021 . The DuraStim® technology is powered by electricity. 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. Pioneer Pressure Pumping Acquisition OnDecember 31, 2018 , we consummated the purchase of pressure pumping and related assets ofPioneer Natural Resources USA, Inc. ("Pioneer") andPioneer 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 ofDecember 31 of each of the calendar years of 2022, 2024 and 2026. Pioneer can increase the number of committed fleets prior toDecember 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 36 -------------------------------------------------------------------------------- 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. Commodity Price and Other Economic Conditions The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other 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 earlyMarch 2020 as a direct result of failed negotiations betweenOPEC , andRussia . 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 ofOPEC as a concession toU.S. producers. After the failure to reach an agreement,Saudi Arabia , a dominant member ofOPEC , 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 ofMarch 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,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 earlyMarch 2020 . Tentative agreements were reached to cut production by up to 10 million BOPD, with allocations to be made among the OPEC+ participants. Some of these production cuts went into effect in the first half ofMay 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 ofJanuary 2020 , when prices were approximately$62 per barrel, through the end ofMarch 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 ofJune 17, 2020 , the WTI price for a barrel of crude oil was approximately$38 . Despite a significant decline in drilling and completion activity byU.S. producers starting inmid-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 theGulf Coast region. The combined effect of the aforementioned factors is anticipated to have a continuing adverse impact on the industry in general and our operations specifically.
2019 Operational Highlights
Over the course of the year ended
related assets (510,000 HHP) acquired in connection with the Pioneer
Pressure Pumping Acquisition, which resulted in an increase to our
revenue and profitability in 2019;
• Purchased 108,000 HHP of DuraStim® hydraulic fracturing pumps with the
first DuraStim® pumps of 54,000 HHP delivered in December 2019 , while
the remaining hydraulic fracturing pumps or 54,000 HHP expected to be
delivered in 2020;
• Entered into a purchase option agreement with our equipment supplier to
purchase additional DuraStim® hydraulic fracturing pumps of 108,000
HHP;
• Maintained a high fleet utilization for the year 2019; and
• Improved operational and financial processes by making changes to
senior management in 2019.
37--------------------------------------------------------------------------------
2019 Financial Highlights
Financial highlights for the year ended
compared to
primarily a result of the increase in our fleet size in connection with
the Pioneer Pressure Pumping Acquisition placed in service at the
beginning of 2019;
• Cost of services (exclusive of depreciation and amortization) increased
million for the year ended
increase in head count and higher activity levels resulting from the
increase in fleet size. Cost of services as a percentage of revenue
decreased to 71.6% in 2019 compared to 74.5% for the year ended
December 31, 2018 ;
• General and administrative expenses, inclusive of stock-based
compensation ("G&A"), increased $51.1 million , or 94.7% to $105.1
million, as compared to
a percentage of revenue increased to 5.1% in 2019 from 3.2% for the
year ended December 31, 2018 . The increase was driven by increase inlegal and professional fees, payroll related expense and net increase
in other G&A expenses resulting partly from the expansion of our
business with the Pioneer Pressure Pumping Acquisition. Included in G&A
was approximately $24.2 million related to legal and professional fees
incurred in connection with the Audit Committee internal review;
• Net income was $163.0 million , compared to $173.9 million for the
December 31, 2018 . Diluted net income per common share was $1.57 ,
compared to
was approximately
year ended
net income in the subsequent section "How We Evaluate Our Operations");
and
• Maintained a conservative balance sheet and sufficient liquidity.
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 our reduced 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 will continue to make
appropriate adjustments to our workforce to reflect outlook 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 payment terms withcertain 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.
38
--------------------------------------------------------------------------------Our Assets and Operations
Through our pressure pumping segment, which includes cementing operations,
we primarily provide hydraulic fracturing services to E&P companies in the
Permian Basin . Our modern hydraulic fracturing fleets have been designed to
handle Permian Basin specific operating conditions and the region's increasingly
highintensity well completions, which are characterized by longer horizontal
wellbores, more frac stages per lateral and increasing amounts of proppant per
well. We continually reinvest in our equipment to ensure optimal performance and
reliability.
In addition to our core pressure pumping segment operations, we also offer
a suite of complementary well completion and production services, including
coiled tubing and other services. We believe these complementary services create
operational efficiencies for our customers and could allow us to capture a
greater portion of their capital spending across the lifecycle of a well in the
future.
How We Generate Revenue
We generate revenue primarily through our pressure pumping segment, and
more specifically, by providing hydraulic fracturing services to our customers.
We own and operate a fleet of mobile hydraulic fracturing units and other
auxiliary equipment to perform fracturing services. We also provide personnel
and services that are tailored to meet each of our customers' needs. We charge
our customers on a perjob basis, in which we set pricing terms after receiving
full specifications for the requested job, including the lateral length of the
customer's wellbore, the number of frac stages per well, the amount of proppant
and chemicals to be used and other parameters of the job. We also could generate
revenue from idle fees from Pioneer in certain circumstances.
In addition to hydraulic fracturing services, we generate revenue through
the complementary services that we provide to our customers, including
cementing, coiled tubing and other services. These complementary services are
provided through various contractual arrangements, including on a turnkey
contract basis, in which we set a price to perform a particular job, or a
daywork contract basis, in which we are paid a set price per day for our
services. We are also sometimes paid by the hour for these complementary
services.
Our revenue, profitability and cash flows are highly dependent upon
prevailing crude oil prices and expectations about future prices. For many
years, oil prices and markets have been extremely volatile. Prices are affected
by many factors beyond our control. WTI oil prices declined significantly in
2015 and 2016 to approximately $30 per barrel, but subsequently recovered in
2017 and 2018. However, in 2019, oil and natural gas prices were highly
volatile. The average WTI oil price per barrel was approximately $57 , $65 and
$51 for the years ended December 31, 2019 , 2018 and 2017, respectively. Demand
for our services is largely dependent on oil and natural gas prices, and our
customers' completion budgets and rig count. In March 2020 , WTI oil prices
declined significantly, to a low of approximately $20 per barrel towards the end
of March 2020 . On June 17, 2020 the WTI oil price was approximately $38 per
barrel. If such depressed prices continue or do not improve, demand for our
services will be negatively impacted and result in a significant decrease in our
profitability and cash flows. We monitor the oil and natural gas prices and the
Permian Basin rig count to enable us to more effectively plan our business and
forecast the demand for our services.
The historical weekly average
Year Ended December 31,
Drilling Type (Permian Basin) 2019 2018 2017
Directional 5 6 6
Horizontal 405 418 311
Vertical 32 43 39
Total 442 467 356
39
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Costs of Conducting our Business
The principal direct costs involved in operating our business are direct labor,
expendables and other direct costs.
Direct Labor Costs. Payroll and benefit expenses related to our crews and other
employees that are directly attributable to the effective delivery of services
are included in our operating costs. Direct labor costs amounted to 19.6% and
13.1% of total costs of service for the years ended December 31, 2019 and 2018,
respectively. The percentage increase in our direct labor costs was driven
primarily by the increase in the crew costs and also the increase in the number
of our customers directly sourcing certain expendables like sand and chemical,
as discussed below, which has the effect of reducing our revenues.
Expendables. Expendables include the product and freight costs associated with
proppant, chemicals and other consumables used in our pressure pumping and other
operations. These costs comprise a substantial variable component of our service
costs, particularly with respect to the quantity and quality of sand and
chemicals demanded when providing hydraulic fracturing services. Expendable
product costs comprised approximately 40.8%, and 56.0% of total costs of service
for the years ended December 31, 2019 and 2018, respectively. The percentage
decrease in our expendable product cost in 2019 is primarily attributable to the
increase in the number of customers sourcing these expendables directly from the
vendors and an increase in the use of less expensive regional sand, and overall
depressed sand prices, which has the effect of reducing our revenues.
Other Direct Costs. We incur other direct expenses related to our service
offerings, including the costs of fuel, repairs and maintenance, general
supplies, equipment rental and other miscellaneous operating expenses. Fuel is
consumed both in the operation and movement of our hydraulic fracturing fleet
and other equipment. Repairs and maintenance costs are expenses directly related
to upkeep of equipment, which have been amplified by the demand for higher
horsepower jobs. Capital expenditures to upgrade or extend the useful life of
equipment are not included in other direct costs. Other direct costs were 39.6%
and 30.9% of total costs of service for the years ended December 31, 2019 and
2018, respectively. The percentage increase in our other direct costs was
primarily a result of the increase in the number of our customers directly
sourcing certain expendables like sand and chemical, as discussed above, which
has the effect of reducing our revenues.
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 IPO and costs related to asset acquisitions or
one-time professional fees. Adjusted EBITDA margin reflects our Adjusted EBITDA
as a percentage of our revenues.
Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by
our management and other users of our financial statements such as investors,
commercial banks, and research analysts, to assess our financial performance
because it allows us and other users to compare our operating performance on a
consistent basis across periods by removing the effects of our capital structure
(such as varying levels of interest expense), asset base (such as depreciation
and amortization), nonrecurring (income) expenses and items outside the control
of our management team (such as income taxes). Adjusted EBITDA and Adjusted
EBITDA margin have limitations as analytical tools and should not be considered
as an alternative to net income (loss), operating income (loss), cash flow from
operating activities or any other measure of financial performance presented in
accordance with generally accepted accounting principles in the United States of
America ("GAAP").
40
--------------------------------------------------------------------------------
Note Regarding NonGAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented
in accordance with GAAP ("non-GAAP"), except when specifically required to be
disclosed by GAAP in the financial statements. We believe that the presentation
of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to
investors in assessing our financial condition and results of operations because
it allows them to compare our operating performance on a consistent basis across
periods by removing the effects of our capital structure, asset base,
nonrecurring (income) expenses and items outside the control of the Company. Net
income (loss) is the GAAP measure most directly comparable to Adjusted EBITDA.
Adjusted EBITDA and Adjusted EBITDA margin should not be considered as
alternatives to the most directly comparable GAAP financial measure. Each of
these non-GAAP financial measures has important limitations as analytical tools
because they exclude some, but not all, items that affect the most directly
comparable GAAP financial measures. You should not consider Adjusted EBITDA and
Adjusted EBITDA margin in isolation or as a substitute for an analysis of our
results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA
margin may be defined differently by other companies in our industry, our
definitions of these non-GAAP financial measures may not be comparable to
similarly titled measures of other companies, thereby diminishing their utility.
Reconciliation of net income (loss) to Adjusted EBITDA ($ in thousands):
Pressure
Pumping All Other Total
Year ended December 31, 2019
Net income (loss) $ 281,090 $ (118,080 ) $ 163,010
Depreciation and amortization 139,348 5,956 145,304
Interest expense 51 7,090 7,141
Income tax expense - 50,494 50,494
Loss on disposal of assets 106,178 633 106,811
Impairment expense - 3,405 3,405
Stockbased compensation - 7,776 7,776
Other expense - 717 717
Other general and administrative expense (1) - 25,208 25,208
Deferred IPO bonus, retention bonus and severance expense 7,093 2,110 9,203 Adjusted EBITDA$ 533,760 $ (14,691 ) $ 519,069 41
--------------------------------------------------------------------------------
Pressure
Pumping All Other Total
Year ended December 31, 2018
Net income (loss) $ 253,196 $ (79,334 ) $ 173,862
Depreciation and amortization 83,404 4,734 88,138
Interest expense - 6,889 6,889
Income tax expense - 51,255 51,255
Loss (gain) on disposal of assets 59,962 (742 ) 59,220
Stockbased compensation - 5,482 5,482
Other expense - 663 663Other general and administrative expense (1) 2 203
205 Deferred IPO bonus 1,832 977 2,809 Adjusted EBITDA$ 398,396 $ (9,873 ) $ 388,523 Pressure Pumping All Other Total Year endedDecember 31, 2017 Net income (loss)$ 50,417 $ (37,804 ) $ 12,613 Depreciation and amortization 51,155 4,473 55,628 Interest expense - 7,347 7,347 Income tax expense - 3,128 3,128 Loss on disposal of assets 38,059 1,027 39,086 Stockbased compensation - 9,489 9,489 Other expense - 1,025 1,025
Other general and administrative expense (1) - 722
722 Deferred IPO bonus 5,491 2,914 8,405 Adjusted EBITDA$ 145,122 $ (7,679 ) $ 137,443 ____________________
(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 in 2019, and legal
settlements in 2018 and 2017.
42-------------------------------------------------------------------------------- Results of Operations We conduct our business through five operating segments: hydraulic fracturing, cementing, coiled tubing, flowback and drilling. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment, pressure pumping. The comparability of the results of operations may have been impacted by the Pioneer Pressure Pumping Acquisition which was consummated onDecember 31, 2018 . The acquisition cost of the assets was comprised of approximately$110.0 million of cash and 16.6 million shares of our common stock. In addition, we entered into a real estate lease for a crew camp facility with Pioneer. The real estate lease for the crew camp was terminated inJuly 2019 . In connection with the consummation of the transaction, we became a long-term service provider to Pioneer, providing pressure pumping and related services for a term of up to ten years. The Pioneer Pressure Pumping Acquisition resulted in an additional 510,000 HHP being deployed at the beginning of 2019. Year EndedDecember 31, 2019 Compared to Year EndedDecember 31, 2018 ($ in thousands, except percentages) Year Ended December 31, Change 2019 2018 Variance % Revenue$ 2,052,314 $ 1,704,562 $ 347,752 20.4 % Less (Add): Cost of services (1) 1,470,356 1,270,577 199,779 15.7 % General and administrative expense (2) 105,076 53,958 51,118 94.7 % Depreciation and amortization 145,304 88,138 57,166 64.9 % Impairment expense 3,405 - 3,405 100.0 % Loss on disposal of assets 106,811 59,220 47,591 80.4 % Interest expense 7,141 6,889 252 3.7 % Other expense 717 663 54 8.1 % Income tax expense 50,494 51,255 (761 ) (1.5 )% Net income$ 163,010 $ 173,862 $ (10,852 ) (6.2 )% Adjusted EBITDA (3)$ 519,069 $ 388,523 $ 130,546 33.6 % Adjusted EBITDA Margin (3) 25.3 % 22.8 % 2.5 % 11.0 % Pressure pumping segment results of operations: Revenue$ 2,001,627 $ 1,658,403 $ 343,224 20.7 % Cost of services$ 1,428,620 $ 1,236,262 $ 192,358 15.6 % Adjusted EBITDA$ 533,760 $ 398,396 $ 135,364 34.0 % Adjusted EBITDA Margin (4) 26.7 % 24.0 % 2.7 % 11.3 % ____________________
(1) Exclusive of depreciation and amortization.
(2) Inclusive of stockbased compensation of
2019 and 2018, respectively.
(3) For definitions of the nonGAAP financial measures of Adjusted EBITDA and
Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted
EBITDA margin to our most directly comparable financial measures calculated
in accordance with GAAP, please read "How We Evaluate Our Operations".
(4) The nonGAAP financial measure of Adjusted EBITDA margin for the pressure
pumping segment is calculated by taking Adjusted EBITDA for the pressure
pumping segment as a percentage of our revenues for the pressure pumping
segment.
43-------------------------------------------------------------------------------- Revenue. Revenue increased 20.4%, or$347.8 million , to$2,052.3 million for the year endedDecember 31, 2019 , as compared to$1,704.6 million for the year endedDecember 31, 2018 . The increase was primarily attributable to the increase in our effectively utilized fleets from approximately 18.8 active fleets in 2018 to 23.9 in 2019, and an increase in demand for our pressure pumping services and certain customer activity, specifically driven by the Pioneer Pressure Pumping Acquisition. The increase in revenue was partly offset by the increase in the number of customers self-sourcing certain consumables like sand. Our pressure pumping segment revenues increased 20.7%, or$343.2 million for the year endedDecember 31, 2019 , as compared to the year endedDecember 31, 2018 . Revenues from services other than pressure pumping increased 9.8%, or approximately$4.5 million , for the year endedDecember 31, 2019 , as compared to the year endedDecember 31, 2018 . The increase in revenues from services other than pressure pumping during the year endedDecember 31, 2019 , was primarily attributable to the increase in demand for our coiled tubing services. Cost of Services. Cost of services increased 15.7%, or$199.8 million , to$1,470.4 million for the year endedDecember 31, 2019 , from$1,270.6 million during the year endedDecember 31, 2018 . Cost of services in our pressure pumping segment increased$192.4 million during the year endedDecember 31, 2019 , as compared to the year endedDecember 31, 2018 . The increases were primarily attributable to higher activity levels, coupled with an increase in personnel headcount following the increase in our operations in connection with the Pioneer Pressure Pumping Acquisition. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 71.4% for the year endedDecember 31, 2019 , as compared to 74.5% for the year endedDecember 31, 2018 . The decrease in cost of services as a percentage of revenue in our pressure pumping segment is attributed to the increased revenue from operational efficiencies and a favorable change in our cost structure driven by our internal cost control initiatives, a decrease in the cost of certain consumables and an increase in the number of customers self-sourcing sand and other consumables, which resulted in significantly higher realized Adjusted EBITDA margins during the year endedDecember 31, 2019 . General and Administrative Expenses. General and administrative expenses increased 94.7%, or$51.1 million , to$105.1 million for the year endedDecember 31, 2019 , as compared to$54.0 million for the year endedDecember 31, 2018 . The net increase was primarily attributable to the increase in retention bonuses, stock-based compensation, and severance and related expenses of$11.0 million driven primarily by the increase in personnel following the Pioneer Pressure Pumping Acquisition, increase in nonrecurring professional fees of$25.0 million , primarily in connection with the Expanded Audit Committee Review, and net increase in our remaining other general and administrative expenses of approximately$15.1 million . Depreciation and Amortization. Depreciation and amortization increased 64.9%, or$57.2 million , to$145.3 million for the year endedDecember 31, 2019 , as compared to$88.1 million for the year endedDecember 31, 2018 . The increase was primarily attributable to additional property and equipment purchased in connection with the Pioneer Pressure Pumping Acquisition and other equipment put into service during the year endedDecember 31, 2019 . Impairment Expense. Impairment expense of$3.4 million , a non-cash expense, was recorded during the year endedDecember 31, 2019 in connection with our vertical drilling rigs and flowback assets resulting from the depressed demand and negative future near-term outlook for our drilling assets and the shutdown of our flowback operations. No impairment expense was recorded in the year endedDecember 31, 2018 . Loss on Disposal of Assets. Loss on the disposal of assets increased 80.4%, or$47.6 million , to$106.8 million for the year endedDecember 31, 2019 , as compared to$59.2 million for the year endedDecember 31, 2018 . The increase was primarily attributable to an increase in our hydraulic fracturing fleet size, and greater intensity of jobs as well as the number of jobs completed. Upon sale or retirement of property and equipment, including certain major components like fluid ends and power ends of our pressure pumping equipment that are replaced, the cost and related accumulated depreciation are removed from the balance sheet and the net amount is recognized as loss on disposal of assets. 44 -------------------------------------------------------------------------------- Interest Expense. Interest expense increased 3.7%, or$0.3 million , to$7.1 million for the year endedDecember 31, 2019 , as compared to$6.9 million for the year endedDecember 31, 2018 . The increase in interest expense was primarily attributable to an increase in our average debt balance in 2019 compared to 2018. Other Expense. Other expense was relatively flat at$0.7 million for the year endedDecember 31, 2019 , similar to$0.7 million for the year endedDecember 31, 2018 . Income Tax Expense. Income tax expense was$50.5 million for the year endedDecember 31, 2019 , as compared to$51.3 million for the year endedDecember 31, 2018 . The slight decrease in our provision for income tax expense is attributable to the decrease in pre-tax book income in 2019 compared to 2018. Our effective tax rate was relatively flat at 23.7% during the year endedDecember 31, 2019 compared to 22.8% during the year endedDecember 31, 2018 . 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. Our borrowing base as ofDecember 31, 2019 was approximately$181.2 million and was approximately$16.8 million as ofJune 19, 2020 . 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 ofDecember 31, 2019 , our borrowings under our ABL Credit Facility was$130.0 million and our total liquidity was$198.7 million , consisting of cash and cash equivalents of$149.0 million and$49.7 million of availability under our ABL Credit Facility. As ofJune 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$15.2 million of availability under our ABL Credit Facility. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Future cash flows are subject to a number of variables, and are highly dependent on the drilling, completion, and production activity by our customers, which in turn is highly dependent on oil and natural gas prices. Depending upon market conditions and other factors, we may issue equity and debt securities or take other actions necessary to fund our business or meet our future long-term liquidity requirements. The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in earlyMarch 2020 . As a result of these developments, the Company expects a material adverse impact on the oil field services we provide and our revenue, results of operations and cash flows. These situations are rapidly changing and additional impacts to the business may arise that we are not aware of currently and the depressed oil and gas industry may take a longer time to recover thereby significantly impacting on revenue, results of operations and cash flows for a longer period of time. 45 --------------------------------------------------------------------------------
Cash and Cash Flows
The following table sets forth our net cash provided by (used in)
operating, investing and financing activities during the years ended
Year Ended December 31,
($ in thousands) 2019 2018 2017
Net cash provided by operating activities
$ 109,257 Net cash used in investing activities$ (495,299 ) $ (280,604 ) $ (281,469 ) Net cash provided by (used in) financing activities$ 56,345 $ (3,724 ) $ 62,565 Operating Activities Net cash provided by operating activities was$455.3 million for the year endedDecember 31, 2019 , as compared to$393.1 million for the year endedDecember 31, 2018 . The net increase of$62.2 million was primarily due to the expansion of our operations following the Pioneer Pressure Pumping Acquisition as well as the associated increase in revenue and cash operating profits, and also impacted by the timing of our receivable collections from our customers and payment to our vendors. Investing Activities Net cash used in investing activities increased to$495.3 million for the year endedDecember 31, 2019 , from$280.6 million for the year endedDecember 31, 2018 . The increase was primarily attributable to the cash payment of approximately$110.0 million in connection with the Pioneer Pressure Pumping Acquisition. In addition, during the year endedDecember 31, 2019 , we paid approximately$145.3 million for 108,000 HHP of DuraStim® hydraulic fracturing units, ancillary equipment and turbines (including an option payment of$6.1 million to purchase an additional 108,000 HHP of DuraStim® fleets through the end of 2020). The remaining cash payments in 2019 were primarily incurred in connection with our maintenance capital expenditures and other growth initiatives. Financing Activities Net cash provided by financing activities was$56.3 million for the year endedDecember 31, 2019 , compared to net cash used of$3.7 million for the year endedDecember 31, 2018 . Our net cash provided by financing activities during the year endedDecember 31, 2019 was primarily driven by proceeds from borrowings of$110.0 million to fund our working capital needs and cash payment for fleets acquired in connection with the Pioneer Pressure Pumping Acquisition, proceeds from exercise of equity awards of$1.2 million which was partially offset by cash used in repayment of borrowings of$50.0 million , repayments of insurance financing of$4.5 million and finance lease payment of approximately$0.3 million . Our net cash used in financing activities during the year endedDecember 31, 2018 was primarily driven by repayment of borrowings of$80.9 million , repayment of insurance financing of$4.5 million , payment of debt issuance costs of$1.7 million , partially offset by proceeds from borrowings of$77.4 million to fund our working capital needs and proceeds from insurance financing of$5.8 million . Future Sources and Use ofCash Capital expenditures for 2020 are projected to be primarily related to maintenance capital expenditures to support our existing assets and growth initiatives, depending on market conditions. We anticipate our capital expenditures will be funded by existing cash, cash flows from operations, and if needed, borrowings under our ABL Credit Facility. Our maintenance capital expenditures are dependent on our operational activity and the intensity on the equipment, among other factors, which could vary throughout the year. In addition, we have an agreement with our equipment manufacturer granting the Company the option to purchase additional DuraStim® hydraulic fracturing pumps of approximately 108,000 HHP with the purchase option expiring at different times throughApril 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. 46 -------------------------------------------------------------------------------- We have repaid all our borrowings, as ofJune 19, 2020 , under our ABL Credit Facility with cash flows from operations and our available cash. Our objective is to maintain a conservative leverage ratio. ThroughJune 19, 2020 , we repaid$130.0 million of our borrowings under the ABL Credit Facility. Credit Facility and Other Financing Arrangements ABL Credit Facility Our ABL Credit Facility, as amended, has a total borrowing capacity of$300 million (subject to the Borrowing Base limit), with a maturity date ofDecember 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 ofDecember 31, 2019 was approximately$181.2 million . The ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i) 10% of the lesser of the facility size or the Borrowing Base or (ii)$22.5 million . Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company. Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero. The weighted average interest rate under our ABL Credit Facility for the year endedDecember 31, 2019 was 4.4%. InMarch 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 endedDecember 31, 2019 toJuly 31, 2020 . Off Balance Sheet Arrangements
We had no off balance sheet arrangements as of
Capital expenditures incurred were $400.7 million during the year ended
December 31, 2019 , as compared to $592.6 million during the year ended
December 31, 2018 . The higher capital expense in 2018 was primarily attributable
to the Pioneer Pressure Pumping Acquisition. We financed the Pioneer Pressure
Pumping Acquisition with a combination of cash from operations and borrowings
under our ABL Credit Facility and the issuance of 16.6 million of our common
shares to Pioneer.
Contractual Obligations
The following table presents our contractual obligations and other
commitments as of December 31, 2019 .
($ in thousands) Payment Due by Period
Total Less than 1 year 1 - 3 years 3- 5 years More than 5 years
ABL Credit Facility (1) $ 130,000 $ - $ - $ 130,000 $ -
Operating leases(2) 1,230 366 766 98 -
Finance leases (2) 2,833 2,833 - - -
Other purchase obligation 9,300 4,815 4,485 - -
Total $ 143,363 $ 8,014 $ 5,251 $ 130,098 $ -
____________________(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. However, assuming a weighted average
interest rate of 4.4%, and that our ABL Credit Facility debt balance remains
the same, our estimated annual interest payment will be
(2) Finance and Operating leases include agreements for various office and yard
locations, excluding short-term leases (see Note 17. Leases and Note 18.
Commitments and Contingencies in the financial statements for additional
disclosures, including estimated interest).
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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 .
Recent Accounting Pronouncements
Disclosure concerning recently issued accounting standards is incorporated
by reference to Note 2 of our Consolidated Financial Statements contained in
this Annual Report.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of
operations is based on our consolidated financial statements, which have been
prepared in accordance with accounting principles generally acceptable in the
United States of America . The preparation of these financial statements requires
us to make estimates and assumptions that affect the reported amounts of assets
and liabilities and the disclosure of contingent assets and liabilities at the
dates of the financial statements and the reported revenues and expenses during
the years. We evaluate these estimates and assumptions on an ongoing basis and
base our estimates on historical experience, current conditions and various
other assumptions that we believe to be reasonable under the circumstances. The
results of these estimates form the basis for making judgments about the
carrying values of assets and liabilities as well as identifying and assessing
the accounting treatment with respect to commitments and contingencies. Our
actual results may materially differ from these estimates.
Listed below are the accounting policies that we believe are critical to
our financial statements due to the degree of uncertainty regarding the
estimates or assumptions involved, and that we believe are critical to the
understanding of our operations.
Property and Equipment
Our property and equipment are recorded at cost, less accumulated depreciation.
Upon sale or retirement of property and equipment, the cost and related
accumulated depreciation are removed from the balance sheet and the net amount,
less proceeds from disposal, is recognized as a gain or loss in earnings.
We primarily retired certain components of equipment such as fluid ends and
power ends, rather than entire pieces of equipment, which resulted in a net loss
on disposal of assets of $106.8 million , $59.2 million and $39.1 million for the
years ended December 31, 2019 , 2018 and 2017, respectively.
Depreciation of property and equipment is provided on the straightline
method over estimated useful lives as shown in the table below. The estimated
useful lives and salvage values of property and equipment is subject to key
assumptions such as maintenance, utilization and job variation. Unanticipated
future changes in these assumptions could negatively or positively impact our
net income. A 10% change in the useful lives of our property and equipment would
have resulted in approximately $14.5 million impact on pre-tax income during the
year ended December 31, 2019 .
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Land Indefinite
Buildings and property improvements 5 - 30 years
Vehicles 1 5 years
Equipment 1 20 years
Leasehold improvements 5 20 years
Impairment of Long-Lived Assets
In accordance with the Financial Accounting Standards Board ("FASB")
Accounting Standards Codification ("ASC") 360 regarding Accounting for the
Impairment or Disposal of LongLived Assets, we review the longlived assets to
be held and used whenever events or circumstances indicate that the carrying
value of those assets may not be recoverable. An impairment loss is indicated if
the sum of the expected future undiscounted cash flows attributable to the
assets is less than the carrying amount of such assets. In this circumstance, we
recognize an impairment loss for the amount by which the carrying amount of the
assets exceeds the estimated fair value of the asset. Our cash flow forecasts
require us to make certain judgments regarding longterm forecasts of future
revenue and costs and cash flows related to the assets subject to review. The
significant assumption in our cash flow forecasts is our estimated equipment
utilization and profitability. The significant assumption is uncertain in that
it is driven by future demand for our services and utilization which could be
impacted by crude oil market prices, future market conditions and technological
advancements. Our fair value estimates for certain longlived assets require us
to use significant other observable inputs, including significant assumptions
related to market approach based on recent auction sales or selling prices of
comparable equipment. The estimates of fair value are also subject to
significant variability, are sensitive to changes in market conditions, and are
reasonably likely to change in the future. We recorded an impairment loss of
$1.2 million during the year ended December 31, 2019 related to our drilling
assets group, because we believe that our cash flow forecasts were negatively
impacted by the depressed vertical drilling market, which led to the idling of
the drilling rigs. Based on observable market inputs, we believe the fair value
of the drilling rigs have declined following the continued market decline in the
demand for vertical drilling services. In addition, we recorded an impairment
loss of $2.2 million related to our flowback assets group because we believe our
future cash flow forecasts were negatively impacted by the decline in the demand
for our flowback services and the general depressed market for flowback
operations.
If the crude oil market declines or the demand for vertical drilling does
not recover, and if the equipment remains idle or underutilized, the estimated
fair value of such equipment may decline, which could result in future
impairment charges. Though the impacts of variations in any of these factors can
have compounding or offsetting impacts, a 10% decline in the estimated fair
value of our drilling assets at December 31, 2019 would result in additional
impairment of $0.2 million .
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 asset impairment. As a result
of the triggering events, we performed 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:
• drilling asset group impairment of approximately $1.1 million as a result
of our recoverability tests; and
• write-off of
additional DuraStim® equipment for which options expire at various times
through the end of
options due to the events described above.
Goodwill is the excess of the consideration transferred over the fair value of the tangible and identifiable intangible assets and liabilities recognized.Goodwill is not amortized. We perform an annual impairment test of goodwill as ofDecember 31 , or more frequently if circumstances indicate that impairment may exist. 49 -------------------------------------------------------------------------------- There were no additions to, or disposal of, goodwill during the year endedDecember 31, 2019 . We performed our annual goodwill impairment test in accordance with ASC 350, Intangibles-Goodwill and Other, onDecember 31, 2019 , at which time, we determined that the fair value of our hydraulic fracturing reporting unit was substantially in excess of its carrying value. The hydraulic fracturing operating segment is the only segment which has goodwill atDecember 31, 2019 . The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted active fleet revenue and cost assumptions. Our discounted cash flow analysis includes significant assumptions regarding discount rates, fleet utilization, expected profitability margin, forecasted maintenance capital expenditures, the timing of an anticipated market recovery, and the timing of expected cash flow. As such, this analysis incorporates inherent uncertainties that are difficult to predict in volatile economic environments and could result in impairment charges in future periods if actual results materially differ from the estimated assumptions utilized in our forecast. InMarch 2020 , crude oil prices declined significantly, an indication that a triggering event has occurred, and as such, we expect to record a goodwill impairment expense of up to$9.4 million during the first quarter of 2020. Income Taxes Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would not be able to fully realize our deferred tax assets in the future in excess of their net recorded amount, we would record a valuation allowance, which would increase our provision for income taxes. In determining our need for a valuation allowance as ofDecember 31, 2019 , we have considered and made judgments and estimates regarding estimated future taxable income. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to record a valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income. Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year. 50
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