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 toProPetro Holding Corp. and its subsidiary.
Overview
We are a growth-oriented,Midland, Texas -based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources. Our operations are primarily focused in thePermian 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 inthe United States , and we believe we are currently one of the largest providers of hydraulic fracturing services in the region by hydraulic horsepower ("HHP"). 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 have eight fleets committed to Pioneer. During times when there is a significant reduction in overall demand for our services, the idle fees could represent a material portion of our revenues. Changes to our customers' well design, shale formations, operating conditions and new technology have resulted in continuous changes to the number of pumps, or units, that constitute a fleet. As a result of the asymmetric nature of the number of pumps that constitute a fleet across our customer base, which we believe will continue to evolve, we view HHP to also be an appropriate metric to measure our available hydraulic fracturing capacity. Our total available HHP atJune 30, 2019 was 1,415,000 HHP in conventional equipment. In 2019, we entered into a purchase commitment for 108,000 HHP of DuraStim® hydraulic fracturing pumps, and inDecember 2019 , we have received 54,000 HHP of the DuraStim® hydraulic fracturing pumps, with the remaining pumps of 54,000 HHP expected to be delivered before the end of 2020. AtDecember 31, 2019 , our total available HHP was 1,469,000 HHP, which was comprised of 1,415,000 HHP of conventional HHP and 54,000 HHP of our newly purchased DuraStim® hydraulic fracturing technology. With the continuous evaluation and changes to the number of pumps or HHP that constitute a fleet, we believe that our available fleet capacity could decline as we reconfigure our fleets to increase active HHP and back up HHP based on our customers' and operational needs. We also have an option to purchase up to an additional 108,000 HHP of DuraStim® hydraulic fracturing pumps in the future throughApril 30, 2021 . The DuraStim® technology is powered by electricity. In 2019, we purchased two gas turbines to provide electrical power for the DuraStim® fleets. The electrical power sources for future DuraStim® fleets are still being evaluated and could either be supplied by the Company, customers or a third-party supplier. Our competitors include many large and small oilfield services companies, including RPC, Inc., Halliburton Company, Patterson-UTI Energy Inc.,Nextier Oilfield Solutions Inc., Inc. , Liberty Oilfield Services Inc., Superior Energy Services Inc., Schlumberger Limited, FTS International Inc. and a number of private companies. Although we believe price is a key factor in E&P companies' criteria in choosing a service provider, we believe that other important factors include operational efficiency, technical expertise, service and equipment quality, and health and safety standards. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our deep local roots, operational expertise, the capability of our modern fleet to handle the most complexPermian Basin well completions, and commitment to safety and reliability. Our substantial market presence in thePermian Basin positions us well to capitalize on drilling and completion activity in the region. Historically, our operational focus has been in thePermian Basin's Midland sub-basin, where our customers have primarily operated. However, with increasing levels ofDelaware sub-basin activity, we have recently expanded our presence in -22- --------------------------------------------------------------------------------
the
Through our pressure pumping segment (which also includes our cementing operations), we primarily provide hydraulic fracturing services to E&P companies in thePermian Basin . Our modern hydraulic fracturing fleet has been designed to handlePermian Basin specific operating conditions and the region's increasingly high-intensity well completions, which are characterized by longer horizontal wellbores, more stages per lateral and increasing amounts of proppant per well. The majority of our fleet has been delivered in recent years, and we continue to fully maintain our equipment through the recent industry downturn to ensure optimal performance and reliability. In addition to our core pressure pumping segment operations, which includes our cementing operations, we also offer a suite of complementary well completion and production services, including coiled tubing and other services. We believe these complementary services create operational efficiencies for our customers and could allow us to capture a greater portion of their capital spending across the lifecycle of a well. Our vertical drilling rigs have been idled since 2016 and if the market for vertical drilling does not improve, and the equipment continues to be idled, the estimated fair value for the drilling rigs may decline, thus resulting in future impairment charges.
Commodity Price and Other Economic Conditions
The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both inthe United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control. The global public health crisis associated with the COVID-19 pandemic has and is anticipated to continue to have an adverse effect on global economic activity for the immediate future and has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. The slowdown in global economic activity attributable to COVID-19 has resulted in a dramatic decline in the demand for energy which directly impacts our industry and the Company. In addition, global crude oil prices experienced a collapse starting in 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 ofApril 2020 ,OPEC reconvened to discuss the matter of production cuts in light of unprecedented disruption and supply and demand imbalances that expanded since the failed negotiations in earlyMarch 2020 . Tentative agreements were reached to cut production by up to 10 million barrels of oil per day, or BOPD, with allocations to be made among the OPEC+ participants. Some of these production cuts went into effect in the first half 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 -23- --------------------------------------------------------------------------------
aforementioned factors is anticipated to have a continuing adverse impact on the industry in general and our operations specifically.
The Permian Basin rig count has decreased significantly from approximately 403 at the beginning of 2020 to 175 inMay 2020 , according toBaker Hughes , and may continue to decline if current market conditions do not improve. As a result of the depressed market conditions and events, the Company expects a material adverse impact on the services we provide resulting from our customers shutting down completions of wells and pricing pressure from our customers to reduce the prices of our services. We expect the reduction in the number of wells completion activities and the pricing pressure from our customers to have a negative impact on our future revenue, results of operations and cash flows. Although the oil and gas market is currently depressed, we still believe thePermian Basin , our primary area of operation, is the leading basin with the lowest break-even production cost inthe United States . If the market rebounds, we believe there will be increased demand for pressure pumping services in thePermian Basin where we operate. Our results of operations have historically reflected seasonal tendencies, typically in the fourth quarter, relating to holiday seasons, inclement winter weather and exhaustion of our customers' annual budgets. As a result, we typically experience declines in our operating results in November and December, even in a stable commodity price and operations environment. The seasonal tendencies and the current depressed oil and gas market conditions could result in a longer time recovery time in the oil and gas industry thereby significantly impacting on revenue, results of operations and cash flows for a longer period of time beyond 2020.
Actions to Address the Economic Impact of COVID-19 and Decline in Commodity Prices
SinceMarch 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 with
certain of our larger vendors and are continuing to increase our diligence in collecting and managing our portfolio of accounts receivables.
We are continuing to evaluate and consider additional cost saving measures. We will continue to prioritize the safety and welfare of our employees and customers through these turbulent times.
How We Evaluate Our Operations
Our management uses a variety of financial metrics, Adjusted EBITDA or Adjusted EBITDA margin to evaluate and analyze the performance of our various operating segments.
Adjusted EBITDA and Adjusted EBITDA margin
We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our earnings, before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) loss/(gain) on extinguishment of debt, (iii) stock-based compensation, and (iv) other unusual or nonrecurring (income)/expenses, such as impairment charges, severance, costs related to our initial public offering and costs related to asset acquisitions or one-time professional fees. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues. -24- -------------------------------------------------------------------------------- Adjusted EBITDA and Adjusted EBITDA margin are supplemental measures utilized by our management and other users of our financial statements such as investors, commercial banks, and research analysts, to assess our financial performance because it allows us and other users to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure (such as varying levels of interest expense), asset base (such as depreciation and amortization), nonrecurring (income)/expenses and items outside the control of our management team (such as income taxes). Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income/(loss), operating income/(loss), cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.
Note Regarding Non-GAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP ("non-GAAP"), except when specifically required to be disclosed by GAAP in the financial statements. We believe that the presentation of Adjusted EBITDA and Adjusted EBITDA margin provide useful information to investors in assessing our financial condition and results of operations because it allows them to compare our operating performance on a consistent basis across periods by removing the effects of our capital structure, asset base, nonrecurring expenses (income) and items outside the control of the Company. Net income is the GAAP measure most directly comparable to Adjusted EBITDA. Adjusted EBITDA and Adjusted EBITDA margin should not be considered as alternatives to the most directly comparable GAAP financial measure. Each of these non-GAAP financial measures has important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. You should not consider Adjusted EBITDA or Adjusted EBITDA margin in isolation or as a substitute for an analysis of our results as reported under GAAP. Because Adjusted EBITDA and Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. -25-
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Reconciliation of net income (loss) to adjusted EBITDA ($ in thousands):
Three Months Ended June 30, 2019 Pressure Pumping All Other Total Net income (loss)$ 64,230 $ (28,097 ) $ 36,133 Depreciation and amortization 34,023 1,459 35,482 Interest expense 22 2,004 2,026 Income tax expense - 10,272 10,272 Loss on disposal of assets 31,117 81 31,198 Stock-based compensation - 2,840 2,840 Other expense - 276 276 Other general and administrative expense(1) - 6,540 6,540 Retention bonus expense 1,795 - 1,795 Adjusted EBITDA$ 131,187 $ (4,625 ) $ 126,562 Three Months Ended June 30, 2018 Pressure Pumping All Other Total Net income (loss)$ 57,524 $ (18,433 ) $ 39,091 Depreciation and amortization 20,042 1,234 21,276 Interest expense - 2,231 2,231 Income tax expense - 12,052 12,052 Loss (gain) on disposal of assets 19,823 (833 ) 18,990 Stock-based compensation - 1,443 1,443 Other expense - 182 182 Other general and administrative expense(1) 2 16 18 Deferred IPO bonus expense 427 258 685 Adjusted EBITDA$ 97,818 $ (1,850 ) $ 95,968 -26-
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Six Months Ended June 30, 2019 Pressure Pumping All Other Total Net income (loss)$ 162,324 $ (56,386 ) $ 105,938 Depreciation and amortization 65,806 2,793 68,599 Interest expense 22 3,906 3,928 Income tax expense - 32,164 32,164 Loss on disposal of assets 50,123 302 50,425 Stock-based compensation - 4,669 4,669 Other expense - 464 464 Other general and administrative expense (1) - 6,540 6,540 Deferred IPO bonus and retention bonus expense 3,953 157 4,110 Adjusted EBITDA$ 282,228 $ (5,391 ) $ 276,837 Six Months Ended June 30, 2018 Pressure Pumping All Other Total Net income (loss)$ 110,458 $ (34,659 ) $ 75,799 Depreciation and amortization 37,805 2,406 40,211 Interest expense - 3,492 3,492 Income tax expense - 22,406 22,406 Loss (gain) on disposal of assets 27,651 (996 ) 26,655 Stock-based compensation - 2,201 2,201 Other expense - 412 412 Other general and administrative expense (1) 2 18 20 Deferred IPO bonus expense 965 551 1,516 Adjusted EBITDA$ 176,881 $ (4,169 ) $ 172,712
(1) Other general and administrative expense primarily relates to nonrecurring
professional fees paid to external consultants in connection with the Expanded Audit Committee Review and advisory services of$6.5 million in 2019, and legal settlement in 2018. -27-
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Results of Operations
We conduct our business through five operating segments: hydraulic fracturing (inclusive of acidizing), cementing, coil tubing, flowback, and drilling. For reporting purposes, the hydraulic fracturing and cementing operating segments are aggregated into our one reportable segment-pressure pumping. All other operating segments and corporate administrative expenses (inclusive of our total income tax expense and interest expense) are included in the ''all other'' category. Total corporate administrative expenses for the three and six months endedJune 30, 2019 were$27.5 million and$57.2 million , respectively, and for the three and six months endedJune 30, 2018 , corporate administrative expenses were$21.2 million and$38.0 million , respectively. In 2020, the Company shut down its flowback operations in 2020 and disposed of the assets. The comparability of the results of operations may have been impacted by the Pioneer Pressure Pumping Acquisition resulting in additional eight fleets deployed at the beginning of 2019. Our hydraulic fracturing operating segment revenue approximated 95.6% and 95.8% of our pressure pumping revenue during the three and six months endedJune 30, 2019 , respectively. During the three and six months endedJune 30, 2018 , our hydraulic fracturing operating segment revenue approximated 95.7% and 95.8% of our pressure pumping revenue, respectively. The following table sets forth the results of operations for the periods presented: (in thousands, except for percentages) Three Months Ended June 30, Change 2019 2018 Variance % Revenue$ 529,494 $ 459,888 $ 69,606 15.1 % Cost of services (1) 386,218 351,888 34,330 9.8 % General and administrative expense (2) 27,889 14,178 13,711 96.7 % Depreciation and amortization 35,482 21,276 14,206 66.8 % Loss on disposal of assets 31,198 18,990 12,208 64.3 % Interest expense 2,026 2,231 (205 ) (9.2 )% Other expense 276 182 94 51.6 % Income tax expense 10,272 12,052 (1,780 ) (14.8 )% Net income$ 36,133 $ 39,091 $ (2,958 ) (7.6 )% Adjusted EBITDA (3)$ 126,562 $ 95,968 $ 30,594 31.9 % Adjusted EBITDA Margin (3) 23.9 % 20.9 % 3.0 % 14.4 % Pressure pumping segment results of operations: Revenue$ 515,867 $ 445,805 $ 70,062 15.7 % Cost of services$ 374,653 $ 341,890 $ 32,763 9.6 % Adjusted EBITDA (3)$ 131,187 $ 97,818 $ 33,369 34.1 % Adjusted EBITDA Margin (4) 25.4 % 21.9 % 3.5 % 16.0 %
(1) Exclusive of depreciation and amortization.
(2) Inclusive of stock-based compensation.
(3) For definitions of the non-GAAP financial measures of Adjusted EBITDA and
Adjusted EBITDA margin and reconciliation of Adjusted EBITDA to our most
directly comparable financial measures calculated in accordance with GAAP,
please read "How We Evaluate Our Operations".
(4) The non-GAAP financial measure of Adjusted EBITDA margin for the pressure
pumping segment is calculated by taking Adjusted EBITDA for the pressure
pumping segment as a percentage of our revenue for the pressure pumping segment. -28-
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Three Months Ended
Revenues. Revenues increased 15.1%, or$69.6 million , to$529.5 million for the three months endedJune 30, 2019 , as compared to$459.9 million for the three months endedJune 30, 2018 . The increase was primarily attributable to the increase in hydraulic fracturing fleet size from 18.8 to 25.6 active fleets, and an increase in demand for our pressure pumping services and customer activity, resulting in an increase in our customer base, during the three months endedJune 30, 2019 . Our pressure pumping segment revenues increased 15.7%, or$70.1 million , for the three months endedJune 30, 2019 , as compared to the three months endedJune 30, 2018 . Revenues from services other than pressure pumping decreased 3.2%, or$0.5 million , to$13.6 million for the three months endedJune 30, 2019 as compared$14.1 million for the three months endedJune 30, 2018 . The decrease in revenues from services other than pressure pumping was primarily attributable to the decrease in customer demand for our flowback services during the three months endedJune 30, 2019 and the disposal of our surface drilling operations inAugust 2018 . Cost of Services. Cost of services increased 9.8%, or$34.3 million , to$386.2 million for the three months endedJune 30, 2019 , as compared to$351.9 million during the three months endedJune 30, 2018 . Cost of services in our pressure pumping segment increased$32.8 million for the three months endedJune 30, 2019 , as compared to the three months endedJune 30, 2018 . These increases were primarily attributable to our increased active fleet count and higher activity levels, resulting in an increase in employee headcount and as well as our material and other direct costs. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 72.6% for the three months endedJune 30, 2019 , as compared to 76.7% for the three months endedJune 30, 2018 . The decrease in cost of services as a percentage of revenue for our pressure pumping segment resulted from a favorable change in our cost structure driven by our internal cost control measures, a decrease in the cost of certain consumables and increase in customer self-sourcing sand and other consumables, which resulted in higher realized Adjusted EBITDA margins during the three months endedJune 30, 2019 . General and Administrative Expenses. General and administrative expenses increased 96.7%, or$13.7 million , to$27.9 million for the three months endedJune 30, 2019 , as compared to$14.2 million for the three months endedJune 30, 2018 . The net increase was primarily attributable to the increases in stock compensation expense of$1.4 million , retention bonus expense of$1.7 million associated with personnel who joined us as part of the Pioneer Pressure Pumping Acquisition, professional fees paid to external consultants in connection with the Expanded Audit Committee Review and advisory services of$6.5 million , insurance and office expenses of$1.9 million , dues/subscription expense of$1.0 million and a net decrease of$1.2 million in other remaining general and administrative expenses. Depreciation and Amortization. Depreciation and amortization increased 66.8%, or$14.2 million , to$35.5 million for the three months endedJune 30, 2019 , as compared to$21.3 million for the three months endedJune 30, 2018 . The increase was primarily attributable to the increase in our fixed asset base as ofJune 30, 2019 , resulting primarily from an increase in our pressure pumping fleet capacity by 73.6% to 1,415,000 HHP in 2019. Loss on Disposal of Assets. Loss on the disposal of assets increased 64.3%, or$12.2 million , to$31.2 million for the three months endedJune 30, 2019 , as compared to$19.0 million for the three months endedJune 30, 2018 . The increase is attributable to the significant increase in our hydraulic fracturing fleet size, greater service intensity of jobs completed, and higher maintenance on certain of our pressure pumping equipment. Interest Expense. Interest expense decreased 9.2%, or$0.2 million , to$2.0 million for the three months endedJune 30, 2019 , as compared to$2.2 million for the three months endedJune 30, 2018 . The decrease in interest expense was primarily attributable to a decrease in our average debt balance during the three months endedJune 30, 2019 compared to the three months endedJune 30, 2018 . Other Expense. There was no significant change in other expense. Other expense was$0.3 million for the three months endedJune 30, 2019 , as compared to$0.2 million for the three months endedJune 30, 2018 . Income Tax Expense. Total income tax expense was$10.3 million resulting in an effective tax rate of 22.1% for the three months endedJune 30, 2019 as compared to$12.1 million and an effective tax rate of 23.6% for the three months endedJune 30, 2018 . The decrease in income tax expense during the three months endedJune 30, 2019 is primarily attributable to the decrease in pre-tax book income during the three months endedJune 30, 2019 as compared to the three months endedJune 30, 2018 . -29- -------------------------------------------------------------------------------- The following table sets forth the results of operations for the periods presented: (in thousands, except for percentages) Six Months Ended June 30, Change 2019 2018 Variance % Revenue$ 1,075,673 $ 845,107 $ 230,566 27.3 % Cost of services (1) 767,741 650,010 117,731 18.1 % General and administrative expense (2) 46,414 26,122 20,292 77.7 % Depreciation and amortization 68,599 40,211 28,388 70.6 % Loss on disposal of assets 50,425 26,655 23,770 89.2 % Interest expense 3,928 3,492 436 12.5 % Other expense 464 412 52 12.6 % Income tax expense 32,164 22,406 9,758 43.6 % Net income$ 105,938 $ 75,799 $ 30,139 39.8 % Adjusted EBITDA (3)$ 276,837 $ 172,712 $ 104,125 60.3 % Adjusted EBITDA Margin (3) 25.7 % 20.4 % 5.3 % 26.0 % Pressure pumping segment results of operations: Revenue$ 1,047,931 $ 820,850 $ 227,081 27.7 % Cost of services$ 745,757 $ 632,360 $ 113,397 17.9 % Adjusted EBITDA (3)$ 282,228 $ 176,881 $ 105,347 59.6 % Adjusted EBITDA Margin (4) 26.9 % 21.5 % 5.4 % 25.1 %
(1) Exclusive of depreciation and amortization.
(2) Inclusive of stock-based compensation.
(3) For definitions of the non-GAAP financial measures of Adjusted EBITDA and
Adjusted EBITDA margin and reconciliation of Adjusted EBITDA to our most
directly comparable financial measures calculated in accordance with GAAP,
please read "How We Evaluate Our Operations".
(4) The non-GAAP financial measure of Adjusted EBITDA margin for the pressure
pumping segment is calculated by taking Adjusted EBITDA for the pressure
pumping segment as a percentage of our revenue for the pressure pumping segment.
Six Months Ended
Revenues. Revenues increased 27.3%, or$230.6 million , to$1,075.7 million for the six months endedJune 30, 2019 , as compared to$845.1 million for the six months endedJune 30, 2018 . The increase was primarily attributable to the increase in hydraulic fracturing fleet size from 18.1 to 26.3 active fleets, demand for our pressure pumping services and customer activity, resulting in an increase in our customer base, during the six months endedJune 30, 2019 . Our pressure pumping segment revenues increased 27.7%, or$227.1 million , for the six months endedJune 30, 2019 , as compared to the six months endedJune 30, 2018 . Revenues from services other than pressure pumping increased 14.4%, or$3.5 million , for the six months endedJune 30, 2019 as compared to the six months endedJune 30, 2018 . The increase in revenues from services other than pressure pumping was primarily attributable to the increase in our coiled tubing units and customer demand for coil tubing services. Cost of Services. Cost of services increased 18.1%, or$117.7 million , to$767.7 million for the six months endedJune 30, 2019 , as compared to$650.0 million during the six months endedJune 30, 2018 . Cost of services in our pressure pumping segment increased$113.4 million for the six months endedJune 30, 2019 , as compared to the six months endedJune 30, 2018 . The increase was primarily attributable to higher activity levels in our pressure pumping operations, hydraulic fracturing fleet size, and an increase in personnel headcount following the increased activity levels. As a percentage of pressure pumping segment revenues, pressure pumping cost of services decreased to 71.2% for the six months endedJune 30, 2019 , as compared to 77.0% for the six months endedJune 30, 2018 . The decrease in cost of services as a percentage of revenue for our pressure pumping segment resulted from a favorable change in our cost structure driven by our internal cost control measures and a decrease in the cost of certain consumables and increase in customer self-sourcing sand and other consumables, which resulted in higher realized Adjusted EBITDA margins during the six months endedJune 30, 2019 . -30- -------------------------------------------------------------------------------- General and Administrative Expenses. General and administrative expenses increased 77.7% or$20.3 million to$46.4 million for the six months endedJune 30, 2019 , as compared to$26.1 million for the six months endedJune 30, 2018 . The net increase was primarily attributable to increases in stock compensation expense of$2.5 million , retention bonus expense of$3.6 million associated with personnel who joined us as part of the Pioneer Pressure Pumping Acquisition, professional fees paid to external consultants in connection with the Expanded Audit Committee Review and advisory services of$6.5 million , office expense of$1.6 million , insurance expense of$2.6 million , dues/subscription of$1.1 million and net aggregate increase in other remaining general and administrative expenses of$2.3 million . Depreciation and Amortization. Depreciation and amortization increased 70.6%, or$28.4 million , to$68.6 million for the six months endedJune 30, 2019 , as compared to$40.2 million for the six months endedJune 30, 2018 . The increase was primarily attributable to the increase in our fixed asset base as ofJune 30, 2019 , resulting primarily from an increase in our pressure pumping fleet capacity by 73.6% to 1,415,000 HHP in 2019. Loss on Disposal of Assets. Loss on the disposal of assets increased 89.2%, or$23.8 million , to$50.4 million for the six months endedJune 30, 2019 , as compared to$26.7 million for the six months endedJune 30, 2018 . The increase is attributable to the significant increase in hydraulic fracturing fleet size, greater service intensity of jobs completed and higher activity levels on certain of our pressure pumping equipment. Interest Expense. Interest expense increased 12.5%, or$0.4 million , to$3.9 million for the six months endedJune 30, 2019 , as compared to$3.5 million for the six months endedJune 30, 2018 . The increase in interest expense was primarily attributable to an increase in our average debt balance during the six months endedJune 30, 2019 compared to the six months endedJune 30, 2018 . Other Expense. There was no significant change in other expense. Other expense was$0.5 million for the six months endedJune 30, 2019 , as compared to$0.4 million for the six months endedJune 30, 2018 . Income Tax Expense. Total income tax expense was$32.2 million resulting in an effective tax rate of 23.3% for the six months endedJune 30, 2019 as compared to$22.4 million and an effective tax rate of 22.8% for the six months endedJune 30, 2018 . The increase in income tax expense during the six months endedJune 30, 2019 is primarily attributable to the increase in pre-tax book income during six months endedJune 30, 2019 as compared to the six months endedJune 30, 2018 . -31-
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Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our revolving credit facility ("ABL Credit Facility"). Our primary uses of cash will be to continue to fund our operations, support growth opportunities and satisfy debt payments. Our borrowing base, as redetermined monthly, is tied to 85.0% of eligible accounts receivable. Changes to our operational activity levels have an impact on our total eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Facility. With the current depressed oil and gas market conditions, we believe our remaining monthly availability under our ABL Credit facility will be adversely impacted by the expected decline in our customers' activity. As ofJune 30, 2019 , our borrowings under our ABL Credit Facility was$150.0 million and our total liquidity was$146.5 million , consisting of cash and cash equivalents of$36.3 million and$110.2 million of availability under our ABL Credit Facility. As 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. 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 ofJune 30, 2019 was approximately$261.8 million and was approximately$16.8 million as ofJune 19, 2020 . The ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio to apply when excess availability is less than the greater of (i)10%of the lesser of the facility size or the Borrowing Base or (ii)$22.5 million . Under this facility we are required to comply, subject to certain exceptions and materiality qualifiers, with certain customary affirmative and negative covenants, including, but not limited to, covenants pertaining to our ability to incur liens, indebtedness, changes in the nature of our business, mergers and other fundamental changes, disposal of assets, investments and restricted payments, amendments to our organizational documents or accounting policies, prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company. Borrowings under the ABL Credit Facility accrue interest based on a three-tier pricing grid tied to availability, and we may elect for loans to be based on either LIBOR or base rate, plus the applicable margin, which ranges from 1.75% to 2.25% for LIBOR loans and 0.75% to 1.25% for base rate loans, with a LIBOR floor of zero. The weighted average interest rate for our ABL Credit Facility for the six months endedJune 30, 2019 was 4.7%. 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 . InJuly 2017 , theUnited Kingdom's Financial Conduct Authority , which regulates LIBOR, announced that it intend to phase out LIBOR by the end of 2021. At the present time, the ABL Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021when LIBOR will be phased out. We have not yet pursued any technical amendment or other contractual alternative to address this matter. We are currently evaluating the potential impact of eventual replacement of the LIBOR interest rate. As ofJune 30, 2019 , we had 108,000 HHP of DuraStim® hydraulic pumps on order for delivery between 2019 and 2020, with an option to purchase an additional 108,000 HHP of DuraStim® hydraulic pumps. We expect the initial 108,000 HHP of fully deployable DuraStim® fleets to cost an aggregate of approximately$179.1 million (including auxiliary and mixing equipment and power turbines), of which approximately$96.7 million has been spent as ofJune 30, 2019 and the remaining -32- -------------------------------------------------------------------------------- approximately$82.4 million is expected to be spent in the second half of 2019 and 2020. We expect to fund these fleet purchases with a combination of (i) cash in hand and (ii) borrowings under our ABL Credit Facility. Future Sources and Use of Cash and Contractual Obligations In the normal course of business, we enter into various contractual obligations that impact on our future liquidity. The table below contains our known material contractual obligations as ofJune 30, 2019 . ($ in thousands) Total Less than 1 year 1 - 3 years 4- 5 years ABL Credit Facility (1)$ 150,000 $ - $ -$ 150,000 Operating leases(2) 1,969 259 1,063 647 Finance leases (2) 3,022 3,022 - - Capital expenditures(3) 48,916 48,916 - - Total$ 203,907 $ 52,197$ 1,063 $ 150,647
(1) Exclusive of future commitment fees, amortization of deferred financing
costs, interest expense or other fees on our revolving credit facility
because obligations thereunder are floating rate instruments and we cannot
determine with accuracy the timing of future loan advances, repayments or
future interest rates to be charged.
(2) Finance and Operating leases include agreements for various office locations,
excluding short-term leases (see Notes (9) Leases and (10) Commitments and
Contingencies in the financial statements for additional disclosures).
(3) Capital expenditures relate to the contractual expenditures (see Note 10
Commitments and Contingencies). Amounts reflected in the table above do not
include any potential capital expenditures associated with the 108,000 HHP of
DuraStim® hydraulic pumps (or associated auxiliary and mixing equipment and
power equipment) that we have an option to purchase through
We have option agreements with our equipment manufacturer to purchase additional DuraStim® hydraulic fracturing pumps of approximately 108,000 HHP 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 before they expire. However, if we decide to exercise our purchase options, it will represent an increase in our growth capital expenditures and we will expect to finance that purchase from our then existing cash on hand, cash flows from operation or borrowings under our ABL Credit Facility.
We have repaid all our borrowings, as of
The Company enters into purchase agreements with the Sand suppliers to secure supply of sand as part of its normal course of business. The agreements with the Sand suppliers require that the Company purchase a minimum volume of sand, constituting substantially all of its sand requirements, from the Sand suppliers, otherwise certain penalties may be charged. Under certain of the purchase agreements, a shortfall fee applies if the Company purchases less than the minimum volume of sand. The shortfall fee represents liquidated damages and is either a fixed percentage of the purchase price for the minimum volumes or a fixed price per ton of unpurchased volumes. Under one of the purchase agreements, the Company is obligated to purchase a specified percentage of its overall sand requirements, or it must pay the supplier the difference between the purchase price of the minimum volumes under the purchase agreement and the purchase price of the volumes actually purchased. Our minimum volume commitments under the purchase agreements are either based on a percentage of our total usage or fixed minimum quantity. Our agreements with the Sand suppliers expire at different times prior toApril 30, 2022 .
In the normal course of business, we enter into various contractual
obligations and routine growth and maintenance capital expenditures that impact
on our future liquidity. There were no other known material contractual
obligations and estimate for future capital expenditures as of
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Cash and Cash Flows
The following table sets forth the historical cash flows for the six
months ended
Six Months Ended June 30, ($ in thousands) 2019 2018 Net cash provided by (used in): Operating activities$ 150,851 $ 124,442 Investing activities$ (324,334 ) $ (149,909 ) Financing activities$ 77,062 $ 28,621
Cash Flows From Operating Activities
Net cash provided by operating activities was$150.9 million for the six months endedJune 30, 2019 , compared to net cash provided by operating activities of$124.4 million for the six months endedJune 30, 2018 . The net increase of$26.4 million was primarily due to the expansion of our operations following the acquisition of Pioneer Pressure Pumping Assets as well as the associated increase in revenue and operating profits from the expansion of operations, and the timing of our receivable from customers and payment to vendors. During the six months endedJune 30, 2019 , our average active fleet count was approximately 26 fleets compared to 18 fleets during the six months endedJune 30, 2018 . Our increase in fleet size has resulted in our ability to service more customer wells and thus increased operating cash flows. Cash Flows From Investing Activities Net cash used in investing activities increased to$324.3 million for the six months endedJune 30, 2019 , from$149.9 million for the six months endedJune 30, 2018 . The increase was primarily attributable to the cash payment of approximately$110.0 million for 510,000 HHP, 4 coiled tubing units and maintenance yard acquired in the Pioneer Pressure Pumping Acquisition. In addition, in the six months endedJune 30, 2019 , we made cash deposits of$102.9 million with our equipment manufacturers for 108,000 HHP of new-build DuraStim® hydraulic fracturing pumps and turbines which are expected to be delivered at different times in 2019 and 2020. Included in our cash deposits with our equipment manufacturers was an option fee of$6.1 million related to our option to acquire 108,000 HHP of additional DuraStim® pumps through the end ofApril 2021 . The option fee will be equally applied towards the purchase price of each additional DuraStim® fleet ordered. We also paid approximately$68.2 million for maintenance capital expenditures and$42.9 million on other growth initiatives during the six months endedJune 30, 2019 . Cash Flows From Financing Activities Net cash provided by financing activities was$77.1 million for the six months endedJune 30, 2019 , and$28.6 million for the six months endedJune 30, 2018 . The net increase in cash provided by financing activities during the six months endedJune 30, 2019 was primarily driven by the increase in net borrowings under our ABL Credit Facility, compared to six months endedJune 30, 2018 . Our net cash provided from financing activities during the six months endedJune 30, 2019 , was primarily driven by additional borrowings under our ABL Credit Facility of$90.0 million , proceeds from equity awards of$1.1 million , and offset by our use of cash for repayment of borrowings of$10.0 million and insurance financing of$3.9 million . Our net cash provided from financing activities during the six months endedJune 30, 2018 was primarily driven by our borrowings of$57.4 million , and offset by our use of cash for repayment of borrowings of$25.2 million , insurance financing of$3.2 million and debt issuance cost of$0.4 million . Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of
There have been no material changes during the six months endedJune 30, 2019 to the methodology applied by our management for critical accounting policies previously disclosed in our Form 10-K. Please refer to Part II, Item 7, "Management Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates" in our Form 10-K for a discussion of our critical accounting policies and estimates. Impairments In the fourth quarter of 2019, management determined that the demand for vertical rigs and flowback services in thePermian Basin continued to be depressed. The Company's (i) vertical drilling rigs were not more likely than not to be utilized in -34- -------------------------------------------------------------------------------- the foreseeable future and (ii) flowback assets were having a deterioration in utilization. As such we expect to record impairment charges of approximately$3.4 million in the fourth quarter of 2019. During the first quarter of 2020, management determined the reductions in commodity prices driven by the potential impact of the novel COVID-19 virus and global supply and demand dynamics coupled with the sustained decrease in the Company's share price were triggering events for goodwill and asset impairment. As a result of the triggering events, we performed an interim goodwill impairment test on the hydraulic fracturing reporting unit and a recoverability tests on each of the assets groups. As a result, we expect to recognize impairments and charges in the first quarter of 2020 as follows:
• goodwill impairment of approximately
• drilling asset group impairment of approximately$1.1 million as a result of our recoverability tests; and • write-off of$6.1 million of deposits related to options to purchase additional DuraStim® equipment for which options expire at various times through the end ofApril 2021 as it is not probable we would exercise our options due to the events describe above. If the depressed oil prices and the current economic conditions remain for a longer period of time, actual results may differ from estimates and future assumptions may change resulting in additional impairment charges in the future. Recently Issued Accounting Standards
Disclosure concerning recently issued accounting standards is incorporated by reference to Note 2 of our Condensed Consolidated Financial Statements (Unaudited) contained in this Form 10-Q.
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