# ProPetro Holding Corp.: Form 10-Q for the period ended Mar 31, 2017

- Company: [ProPetro Holding Corp.](/companies/pump.md) (CIK 1680247)
- Form: 10-Q
- Filed: 2017-05-12
- Accepted by EDGAR: May 12, 2017, 16:53 ET
- Period: 2017-03-31
- Accession: 0001680247-17-000008
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1680247/000168024717000008/a10-q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1680247/000168024717000008/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2017-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Operating income | 3 months, 2017-01-01 to 2017-03-31 | −$19.1m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2017-01-01 to 2017-03-31 | $5.2m | us-gaap:InterestExpense |
| Income tax | 3 months, 2017-01-01 to 2017-03-31 | $116.0k | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2017-01-01 to 2017-03-31 | −$24.4m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2017-01-01 to 2017-03-31 | −$0.43 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2017-01-01 to 2017-03-31 | −$0.43 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2017-01-01 to 2017-03-31 | 55,996,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2017-01-01 to 2017-03-31 | −$3.4m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2017-01-01 to 2017-03-31 | $50.9m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2017-03-31 | $85.6m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2017-03-31 | $209.0m | us-gaap:AssetsCurrent |
| Total assets | at 2017-03-31 | $521.2m | us-gaap:Assets |
| Current liabilities | at 2017-03-31 | $134.0m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2017-03-31 | $147.0m | us-gaap:Liabilities |
| Long-term debt | at 2017-03-31 | $11.7m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2017-03-31 | $6.1m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2017-03-31 | $374.2m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 29,733 characters.

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 Prospectus as well as the financial and other information included therein.

Unless otherwise indicated, references in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" to the "Company," "we," "our," "us" or like terms refer to ProPetro Holding Corp. and its subsidiary.

### Overview

We are a growth-oriented, Midland, Texas-based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated longstanding customer relationships with some of the region's most active and well-capitalized E&P companies. The Permian Basin is widely regarded as the most prolific oil-producing area in the United States, and we believe we are currently one of the largest provider of hydraulic fracturing services in the region by hydraulic horsepower, or HHP, with an aggregate deployed capacity of 420,000 HHP. Our fleet, which consists of 10 hydraulic fracturing fleets, has been designed to handle the highest intensity, most complex hydraulic fracturing jobs and has been 100% utilized since September 2016. Additionally, we have purchased, or contracted to purchase, four additional hydraulic fracturing fleets scheduled for delivery and deployment to dedicated customers in 2017, with two fleets scheduled for delivery in the second quarter, and two fleets scheduled for delivery by year end. These units will provide us with an additional 90,000 HHP, bringing our total capacity to 600,000 HHP in aggregate capacity.

Through our pressure pumping segment (which also includes cementing and acidizing operations), we primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. Our modern hydraulic fracturing fleet has been designed to handle Permian Basin specific operating conditions and the region's increasingly high-intensity well completions, which are characterized by longer horizontal wellbores, more frac stages per lateral and increasing amounts of proppant per well. Over 75% of our fleet has been delivered over the past four years, and we have fully maintained our equipment throughout the recent industry downturn to ensure optimal performance and reliability. Additionally, all of the hydraulic horsepower delivered over the last four years has been sourced from a single manufacturer, leading to a homogeneous fleet with streamlined maintenance programs and training for our personnel.

In addition to our core pressure pumping segment operations, we also offer a suite of complementary well completion and production services, including coiled tubing, flowback and surface air drilling. We believe these complementary services create operational efficiencies for our customers and allow us to capture a greater portion of their capital spending across the lifecycle of a well. Additionally, we believe that these complementary services should benefit from a continued industry recovery and that we are well positioned to continue expanding these offerings in response to our customers increasing service needs and spending levels.

### Industry Trends and Outlook

The oil and gas industry has traditionally been volatile and is influenced by a combination of long-term, short-term and cyclical trends, including domestic and international supply and demand for oil and gas, current and expected future prices for oil and gas and the perceived stability and sustainability of those prices, and capital investments of E&P companies toward their development and production of oil and gas reserves. The oil and gas industry is also impacted by general domestic and international economic conditions, political instability in oil producing countries, government regulations (both in the United States and internationally), levels of consumer demand, adverse weather conditions, and other factors that are beyond our control. Declines and sustained weakness in crude oil prices began in the fourth quarter of 2014 and continued into February 2016, when the closing crude oil prices reached a low of $26.19 per barrel. This decline in oil prices caused our customers to reduce drilling and completion activity and curtail spending. These declines adversely affected the demand for our equipment and services and negatively impacted the prices we were able to charge our customers.

Most recently, the recovery of crude oil prices to the low $50 per barrel range since December 2016 through April 2017, has driven a considerable increase in drilling and completion activity, and associated demand for our services. The Permian Basin, our primary area of operation, is leading the recovery with the number of active drilling rigs increasing 148% from a low of 137 rigs in the basin as of May 2016 to 340 rigs in the basin as of April 2017, according to Baker Hughes. In addition to increased activity levels in the Permian Basin, several evolving industry trends, including increasingly longer horizontal wellbore laterals, a greater number of frac stages per lateral and increasing amounts of proppant employed per well, have significantly increased demand for our hydraulic fracturing and other completion services.

As the Permian Basin shifts further towards more intensive horizontal drilling, operators and service providers are expected to continue to place significant focus on drilling and completion efficiencies, such as multi-well pads and zipper fracs. Multi-well pads allow for the drilling of multiple wellbores from a single topside location, reducing average drilling time. Similarly, zipper fracking allows for the alternating completion of hydraulic fracturing stages in adjacent wells, increasing the number of stages that can be performed in a given time period. These advancements have resulted in a reduction in the number of days typically required to drill and complete a well and increased the total number of wells that can be drilled per rig, which, in turn, drives incremental demand for hydraulic fracturing services.

Rising producer activity levels, increasing basin service intensity and continued drilling and completion efficiencies have combined to drive the 100% utilization of our fleet and build a sizable backlog of addressable demand for our services. We have seen our competitors defer necessary maintenance capital spending, cannibalize existing units for spare parts and idle HHP. This has resulted in tightening hydraulic fracturing supply and demand fundamentals and is driving pricing improvement for our hydraulic fracturing services. Moreover, we believe the other complementary services we provide are well-positioned to similarly benefit from a continued industry recovery.

Our competitors include many large and small oilfield services companies, including RPC, Inc., Halliburton, C&J Energy Services, Patterson-UTI Energy Inc., Superior Energy Services, Schlumberger and a number of private companies. Competitive factors impacting sales of our services are price, reputation and technical expertise, service and equipment quality, and health and safety standards. Although we believe our customers consider all of these factors, we believe price is a key factor in E&P companies' criteria in choosing a service provider. While we seek to price our services competitively, we believe many of our customers elect to work with us based on our deep local roots, operational expertise, the capability of our modern fleet to handle the most complex Permian Basin well completions, and commitment to safety and reliability.

Our substantial market presence in the Permian Basin positions us well to capitalize on increasing drilling and completion activity in the region. Historically, our operational focus has been in the Permian Basin's Midland sub-basin, where our customers have primarily operated. More recently however, with increasing levels of Delaware Basin activity, we have recently expanded our presence in the Delaware Basin in response to increasing levels of demand pull from our customers. Given our entrenched relationships with a variety of Delaware Basin operators, we believe that we are uniquely positioned to capture large addressable growth opportunity as the basin develops. Over time, we expect the Permian Basin's Midland and Delaware sub-basins to continue to command a disproportionate share of future North American E&P spending.

### How We Evaluate Our Operations

Our management uses a variety of financial and operating metrics to evaluate and analyze the performance of our business, including Adjusted EBITDA and Adjusted EBITDA margin.

### EBITDA, Adjusted EBITDA and Adjusted EBITDA margin

We view Adjusted EBITDA and Adjusted EBITDA margin as important indicators of performance. We define EBITDA as our net income, 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) gain on extinguishment of debt, (iii) stock based compensation, and (iv) other unusual or nonrecurring expenses, such as costs related to our initial public offering. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.

EBITDA, 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, research analysts and others, to assess our financial performance because it allows us 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 expenses (such as IPO bonus) and items outside the control of our management team (such as income tax rates). EBITDA, Adjusted EBITDA and Adjusted EBITDA margin have limitations as analytical tools and should not be considered as an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.

### Note Regarding Non-GAAP Financial Measures

EBITDA, Adjusted EBITDA and Adjusted EBITDA margin are not financial measures presented in accordance with GAAP. We believe that the presentation of these non-GAAP financial measures provide useful information to investors in assessing our financial condition and results of operations. Net income is the GAAP measure most directly comparable to Adjusted EBITDA. Our non-GAAP financial measures 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.

#### Reconciliation of net loss to adjusted EBITDA:

*($ in thousands)*

| Three months ended March 31, 2017 | Pressure Pumping | All Other | Total |
| --- | ---: | ---: | ---: |
| Net loss | $(7,918) | $(16,433) | $(24,351) |
| Depreciation and amortization | 9,995 | 1,156 | 11,151 |
| Interest expense | — | 5,175 | 5,175 |
| Income tax expense | — | 116 | 116 |
| EBITDA | 2,077 | (9,986) | (7,909) |
| Loss/(Gain) on disposal of assets | 10,709 | (267) | 10,442 |
| Stock-based compensation | — | 7,369 | 7,369 |
| Other income | — | (26) | (26) |
| IPO bonus expense | 4,133 | 2,219 | 6,352 |
| Adjusted EBITDA | $16,919 | $(691) | $16,228 |
| **Three months ended March 31, 2016** |  |  |  |
| Net loss | $(11,160) | $(1,780) | (12,940) |
| Depreciation and amortization | 9,410 | 1,675 | 11,085 |
| Interest expense | — | 5,415 | 5,415 |
| Income tax benefit | — | (6,792) | (6,792) |
| EBITDA | (1,750) | (1,482) | (3,232) |
| Loss/(Gain) on disposal of assets | 4,771 | (4) | 4,767 |
| Stock-based compensation | — | 206 | 206 |
| Other expense | — | 298 | 298 |
| Adjusted EBITDA | $3,021 | $(982) | 2,039 |

- 19-

### Results of Operations

We conduct our business through seven operating segments: hydraulic fracturing, cementing, acidizing, coil tubing, flowback, surface drilling, and Permian drilling. For reporting purposes, the hydraulic fracturing, cementing and acidizing operating segments are aggregated into our one reportable segment—pressure pumping. We expect revenues and costs of services related to our Permian drilling operating segment to comprise a lower percentage of total revenues and total costs of service in future results of operations when compared to historic results due to our increased focus on pressure pumping and other complementary service offerings. We anticipate the financial significance of this service line relative to the financial results from pressure pumping and other service offerings to continue to decline.

### Three Months Ended March 31, 2017 Compared To Three Months Ended March 31, 2016

*($ in thousands, except for percentages)*

|  | Three Months Ended March 31, 2017 | 2016 |
| --- | ---: | ---: |
| Revenue | $171,931 | $87,930 |
| Cost of services (1) | 149,565 | 80,289 |
| General and administrative expense (2) | 19,859 | 5,808 |
| Depreciation and amortization | 11,151 | 11,085 |
| Loss on disposal of assets | 10,442 | 4,767 |
| Interest expense | 5,175 | 5,415 |
| Other (income)/expense | (26) | 298 |
| Income tax expense/(benefit) | 116 | (6,792) |
| Net loss | $(24,351) | $(12,940) |
| ​ | ​ | ​ |
| Adjusted EBITDA (3) | $16,228 | $2,039 |
| Adjusted EBITDA Margin (3) | 9.44% | 2.32% |
| Pressure pumping segment results of operations: |  |  |
| Revenue | $163,840 | $79,545 |
| Cost of services | $143,372 | $73,341 |
| Adjusted EBITDA | $16,919 | $3,021 |
| Adjusted EBITDA Margin (4) | 10.33% | 3.80% |

(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.

*Revenues.* Revenues increased 95.5%, or $84.0 million, to $171.9 million for the quarter ended March 31, 2017 as compared to $87.9 million for the quarter ended March 31, 2016. The increase was primarily attributable to the increase in customer activity and demand for our services, which has led to an increase in pricing for our hydraulic fracturing and other services. Our pressure pumping segment revenues increased 106.0%, or $84.3 million, for the quarter ended March 31, 2017 as compared to the quarter ended March 31, 2016. Revenues from services other than pressure pumping decreased 3.5%, or $0.3 million, for the quarter ended March 31, 2017 as compared to the quarter ended March 31, 2016. The decrease in revenues from services other than pressure pumping was primarily attributable to the idling of our Permian drilling rigs, offset by the increase in revenues and customer demand for our coil tubing and surface drilling services in the quarter ended March 31, 2017.

*Cost of Services.* Cost of services increased 86.3%, or $69.3 million, to $149.6 million for the quarter ended March 31, 2017, from $80.3 million during the quarter ended March 31, 2016. Cost of services in our pressure pumping segment increased $70.0 million for the quarter ended March 31, 2017 as compared to the quarter ended March 31, 2016. The increases were primarily attributable to higher activity levels, coupled with 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 87.5% for the quarter ended March 31, 2017 as compared to 92.2% for the quarter ended March 31, 2016. The decrease in cost of services as a percentage of revenue for the pressure pumping segment resulted from greater pricing power as demand for our services increased, without a corresponding increase in costs, which resulted in significantly higher realized Adjusted EBITDA margins during the quarter ended March 31, 2017.

*General and Administrative Expenses.* General and administrative expenses increased 242%, or $14.1 million, to $19.9 million for the quarter ended March 31, 2017 as compared to $5.8 million for the quarter ended March 31, 2016. The increase was primarily attributable to non-recurring expenses— an IPO cash bonus of $6.4 million to key members of management along with a $6.8 million of accelerated stock compensation in connection with the IPO and nonrecurring stock compensation for restricted stock units. General and administrative expenses, excluding nonrecurring expenses, as a percentage of total revenues decreased to 3.9% for the quarter ended March 31, 2017 as compared to 6.6% for the quarter ended March 31, 2016, and the decrease is as a result of the higher revenue in the quarter ended March 31, 2017.

*Depreciation and Amortization.* Depreciation and amortization increased 0.6%, or $0.1 million, to $11.2 million for the quarter ended March 31, 2017 as compared to $11.1 million for the quarter ended March 31, 2016. The marginal increase was primarily attributable to additional property and equipment purchased and put into service during the quarter ended March 31, 2017. We calculate depreciation of property and equipment using the straight-line method.

*Loss on Disposal of Assets.* Loss on the disposal of assets increased 119.1%, or $5.7 million, to $10.4 million for the quarter ended March 31, 2017 as compared to $4.8 million for the quarter ended March 31, 2016. The increase was primarily attributable to greater service intensity of jobs completed coupled with higher activity levels and utilization of our equipment.

*Interest Expense.* Interest expense decreased 4.4%, or $0.2 million, to $5.2 million for the quarter ended March 31, 2017 as compared to $5.4 million for the quarter ended March 31, 2016. The decrease in interest expense was primarily attributable to a reduction in our average debt balance during 2017 due to the early retirement of our Term Loan and Revolving Credit Facility. Additionally, the decrease in interest expense was partially offset by the $3.0 million write-off of our deferred loan costs for the early retirement of the related Term Loan and Revolving Credit Facility.

*Other Income/(Expense).* Other income was $0.03 million for the quarter ended March 31, 2017 as compared to other expense of $0.3 million for the quarter ended March 31, 2016. The change from other expense to other income was primarily attributable to a recorded unrealized gain resulting from the change in the fair value of our interest rate swap liability at March 31, 2017 compared to March 31, 2016 where we recorded an unrealized loss.

*Income Tax (Expense)/Benefit.* For the three months ended March 31, 2017, the Company has utilized the discrete effective tax rate method as allowed by Accounting Standards Codification (“ASC”) 740-270-30-18, *Income Taxes - Interim Reporting* to calculate its interim tax provision. The discrete method treats the year to date period as if it was the annual period and determines the income tax expense or benefit on that basis. The Company believes that, at this time, the use of this discrete method is more appropriate than the annual effective tax rate method as the annual effective tax rate is not reliable due to small changes in estimated “ordinary” income would result in significant changes in the estimated annual effective tax rate. Total income tax expense was $0.1 million resulting in a negative effective tax rate of 0.48% for the quarter ended March 31, 2017 as compared to total income tax benefit of $6.8 million and a positive effective tax rate of 34.42% for the quarter ended March 31, 2016. The negative effective tax rate is primarily due to the Company’s full valuation allowance position, impact of indefinite lived assets, and state tax expense which creates a deviation from the customary relationship between income tax (expense)/benefit and pre-tax income/(loss).

### Liquidity and Capital Resources

As of March 31, 2017, our cash and cash equivalents were $85.6 million, as compared to $133.6 million at December 31, 2016. Historically, our primary sources of liquidity and capital resources have been borrowings under our term loan and revolving credit facility, cash flows from our operations and capital contributions from our shareholders. Our primary uses of capital have been investing in and maintaining our property and equipment, repaying indebtedness and for our working capital needs.

Effective as of March 22, 2017, we completed our initial public offering of 13,250,000 shares of common stock at $14.00 per share, from which we received net proceeds of $170.1 million using the proceeds (i) to repay the remaining balance on our term loan, (ii) to acquire additional hydraulic fracturing units and (iii) for general corporate purposes.

On March 22, 2017, the Company entered into a new revolving credit facility with a $150 million borrowing capacity ("ABL Credit Facility"). 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 no LIBOR floor. Borrowings under the ABL Credit Facility are secured by a first priority lien and security interest in substantially all assets of the Company. The ABL Credit Facility has a tenor of 5 years and a borrowing base of 85% of eligible accounts receivables less customary reserves. 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 lien, 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, making prepayments of certain debt, dividends, transactions with affiliates, and certain other activities. In addition, the ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio ("FCCR") of 1.0x when excess availability is less than the greater of (i) 10% of the lesser of the facility size and the borrowing base (as set forth in the ABL Credit Facility) and (ii) $12 million. The ABL has a commitment fee of 0.25% if the utilization is greater than 50% of the borrowing base, otherwise it is 0.375%.

We expect that our primary sources of liquidity and capital resources will be cash flows generated by operating activities and borrowings under our new ABL Credit Facility. We expect that our primary uses of capital will be to continue to fund our operations, support organic growth opportunities and satisfy future debt payments, if incurred.

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 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 obligations.

### Working Capital

Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. The following table presents the components of our working capital as of March 31, 2017 compared to December 31, 2016.

*($ in thousands)*

| Current Assets: | March 31, 2017 | December 31, 2016 |
| --- | ---: | ---: |
| Cash and cash equivalents | $85,625 | $133,596 |
| Accounts receivable - net of allowance for doubtful accounts | 109,866 | 115,179 |
| Inventories | 5,154 | 4,713 |
| Prepaid expenses | 3,938 | 4,608 |
| Other current assets | 4,418 | 6,684 |
| Total current assets | $209,001 | $264,780 |
| **Current Liabilities:** |  |  |
| Accounts payable | $118,255 | $129,093 |
| Accrued liabilities | 9,681 | 13,619 |
| Current portion of long-term debt | 6,087 | 16,920 |
| Accrued interest payable | — | 109 |
| Total current liabilities | $134,023 | $159,741 |
| Working Capital | $74,978 | $105,039 |

Our working capital totaled $75.0 million and $105.0 million at March 31, 2017 and December 31, 2016, respectively. The $30.1 million decrease in working capital is primarily attributable to our use of cash for repayment of debt of $161.7 million, capital expenditures of $50.9 million, and other operating expenditures, partially offset by the receipt of $170.1 million (net of IPO underwriting discounts, commissions and other offering expenses) from our the proceeds of the IPO.

### Cash and Cash Flows

Our cash and cash equivalents were $85.6 million and $133.6 million at March 31, 2017 and December 31, 2016, respectively.

The following table sets forth the historical cash flows for the three months ended March 31, 2017 and 2016 :

*($ in thousands)*

| Net cash (used in) provided by: | Three Months Ended March 31, 2017 | 2016 |
| --- | ---: | ---: |
| Operating activities | $(3,394) | $14,244 |
| Investing activities | $(50,458) | $(12,188) |
| Financing activities | $5,881 | $(5,246) |

### Operating Activities

Net cash used in operating activities was $3.4 million for the quarter ended March 31, 2017, compared to net cash provided by operating activities of $14.2 million for the quarter ended March 31, 2016. The net decrease of $17.6 million was primarily due to increased working capital needs resulting from higher and expanding activity levels.

### Investing Activities

Net cash used in investing activities increased to $50.5 million for the quarter ended March 31, 2017, from $12.2 million during the quarter ended March 31, 2016. The increase was primarily attributable to the new additional hydraulic fracturing units and other ancillary equipment purchased, and a slight increase in capital expenditure related to maintenance, during the quarter ended March 31, 2017, compared to the quarter ended March 31, 2016.

### Financing Activities

Net cash provided by financing activities was $5.9 million for the quarter ended March 31, 2017, and net cash used in financing activities was $5.2 million for the quarter ended March 31, 2016. The net increase in cash provided was primarily due to the receipt of $185.5 million of IPO proceeds, partially offset by payment of IPO costs of $15.1 million and $161.7 million in repayment of borrowings, during the quarter ended March 31, 2017, compared to net cash used of $4.0 million for repayment of borrowings during the quarter ended March 31, 2016.

### Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2017.

### Recently Issued Accounting Standards

Disclosure concerning recent accounting standards is incorporated by reference to Note 2 of our condensed consolidated financial statements (Unaudited) contained in this Form 10-Q.

### Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. Oil prices declined significantly during the second half of 2014. The closing price of oil, which was as high as $105.68 per barrel during the third quarter of 2014, averaged $48.69 during 2015 and reached a twelve-year low of $26.19 in February 2016. However, oil prices have recovered in the third quarter of 2016, and averaged $50 during the first quarter of 2017. As a result of the recent recovery in oil prices, our industry has experienced a significant increase in both drilling and pressure pumping activity levels. Looking forward, assuming commodity prices remain at or above recent levels, we believe U.S. rig counts will continue to increase. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices.

## Market risk

As filed, 276 characters.

As of March 31, 2017, there have been no material changes in market risk from the information provided in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” or “Quantitative and Qualitative Disclosures About Market Risk” in our Prospectus.

## Controls and procedures

As filed, 1,633 characters.

#### Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that the information required to be disclosed by us in our reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2017.

#### Changes in Internal Controls over Financial Reporting.

No changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the quarterly period ended March 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 413 characters.

There have been no material changes to our principal risks that we believe are material to our business, results of operations, and financial condition from the risk factors previously disclosed in our final prospectus dated March 16, 2017 and filed with the SEC pursuant to Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 20, 2017, which is accessible on the SEC’s website at *www.sec.gov.*

Filed May 12, 2017.
Source: SEC EDGAR, the filing index for accession 0001680247-17-000008. Last ingested by Listed: Nov 2, 2026, 18:28 ET. No prices; not investment advice.