# ProPetro Holding Corp.: Form 10-Q for the period ended Mar 31, 2018

- Company: [ProPetro Holding Corp.](/companies/pump.md) (CIK 1680247)
- Form: 10-Q
- Filed: 2018-05-09
- Accepted by EDGAR: May 9, 2018, 16:37 ET
- Period: 2018-03-31
- Accession: 0001680247-18-000044
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1680247/000168024718000044/a10q03312018.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1680247/000168024718000044/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2018-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Operating income | 3 months, 2018-01-01 to 2018-03-31 | $48.6m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2018-01-01 to 2018-03-31 | $1.3m | us-gaap:InterestExpense |
| Income tax | 3 months, 2018-01-01 to 2018-03-31 | $10.4m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2018-01-01 to 2018-03-31 | $36.7m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2018-01-01 to 2018-03-31 | $0.42 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2018-01-01 to 2018-03-31 | $0.44 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2018-01-01 to 2018-03-31 | 86,848,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2018-01-01 to 2018-03-31 | $54.6m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2018-01-01 to 2018-03-31 | $75.1m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2018-03-31 | $46.4m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2018-03-31 | $313.8m | us-gaap:AssetsCurrent |
| Total assets | at 2018-03-31 | $850.3m | us-gaap:Assets |
| Current liabilities | at 2018-03-31 | $282.3m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2018-03-31 | $399.6m | us-gaap:Liabilities |
| Long-term debt | at 2018-03-31 | $102.3m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2018-03-31 | $15.0m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2018-03-31 | $450.7m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 32,489 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 Form 10-K as well as the financial and other information included therein.

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

### Overview

We are a growth-oriented, Midland, Texas-based oilfield services company providing hydraulic fracturing and other complementary services to leading upstream oil and gas companies engaged in the exploration and production ("E&P") of North American unconventional oil and natural gas resources. Our operations are primarily focused in the Permian Basin, where we have cultivated long-standing customer relationships with some of the region's most active and well-capitalized E&P companies. The Permian Basin is widely regarded as the most prolific oil-producing area in the United States, and we believe we are currently one of the largest providers of hydraulic fracturing services in the region by hydraulic horsepower, or HHP, with a current aggregate deployed capacity of 815,000 HHP. At March 31, 2018, our fleet, which consists of 18 hydraulic fracturing fleets, has been designed to handle the highest intensity, most complex hydraulic fracturing jobs and has remained 100% utilized since the beginning of 2017. During the first quarter ended March 31, 2018, we put two new hydraulic fracturing fleets (45,000 HHP per fleet) and enhanced our legacy fleets by an incremental 35,000 HHP. In addition, we have committed to acquire two new additional hydraulic fracturing fleets (45,000 HHP per fleet) which are expected to be delivered and put into service in the second and fourth quarters of 2018, bringing our aggregate capacity to 905,000 HHP or 20 fleets, by the end of 2018.

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. The majority of our fleet has been delivered in recent years, and we have fully maintained our equipment throughout the recent industry downturn to ensure optimal performance and reliability. Additionally, substantially all of the hydraulic horsepower 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, drilling 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 price 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, crude oil prices have averaged over $60 per barrel in April of 2018. Recent prices have resulted in 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 from a low of 137 rigs in the basin as of May 2016 to 443 rigs in the basin as of March 2018, 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 fractured 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 fracturing 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. During the recent downturn, we saw our competitors defer necessary maintenance capital spending and cannibalize existing units for spare parts and idle HHP. This has resulted in tightening hydraulic fracturing supply and demand fundamentals and could drive 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., Keane Group, Inc., Liberty Oilfield Services, Superior Energy Services, Schlumberger, FTS International 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. However, with increasing levels of Delaware Basin activity, we have recently expanded our presence in the Delaware Basin in response to demand 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.

### 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 (loss), before (i) interest expense, (ii) income taxes and (iii) depreciation and amortization. We define Adjusted EBITDA as EBITDA, plus (i) loss/(gain) on disposal of assets, (ii) stock based compensation, and (iii) other unusual or nonrecurring expenses, such as impairment charges and costs related to our initial public offering. 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, research analysts and others, 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 tax rates). 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. 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 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 and items outside the control of the Company. 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 income (loss) to adjusted EBITDA:

*($ in thousands)*

|  | Three months ended March 31, 2018 Pressure Pumping | All Other | Total |
| --- | ---: | ---: | ---: |
| Net income (loss) | $52,934 | $(16,226) | $36,708 |
| Depreciation and amortization | 17,763 | 1,173 | 18,936 |
| Interest expense | — | 1,261 | 1,261 |
| Income tax expense | — | 10,353 | 10,353 |
| Loss/(gain) on disposal of assets | 7,828 | (163) | 7,665 |
| Stock-based compensation | — | 758 | 758 |
| Other expense | — | 230 | 230 |
| Other general and administrative expense (1) | — | 1 | 1 |
| Deferred IPO bonus expense | 538 | 294 | 832 |
| Adjusted EBITDA | $79,063 | $(2,319) | $76,744 |
|  | **Three months ended March 31, 2017** |  |  |
| **($ in thousands)** | **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 |
| Loss/(gain) on disposal of assets | 10,709 | (267) | 10,442 |
| Stock-based compensation | — | 7,369 | 7,369 |
| Other income | — | (26) | (26) |
| Deferred IPO bonus expense | 4,133 | 2,219 | 6,352 |
| Adjusted EBITDA | $16,919 | $(691) | $16,228 |

(1) Other general and administrative expense relates to legal settlement expense.

### Results of Operations

We conduct our business through six operating segments: hydraulic fracturing (inclusive of acidizing), cementing, coil tubing, flowback, surface drilling, 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 are included in the ‘‘all other’’category. We expect revenues and costs of services related to our 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.

The following table sets forth the results of operations for the periods presented (in thousands, except for percentages):

|  | Three Months Ended March 31, 2018 | 2017 | Change Variance% |  |
| --- | ---: | ---: | ---: | ---: |
| Revenue | $385,219 | $171,931 | 213,288 | 124.1% |
| Cost of services (1) | 298,122 | 149,565 | 148,557 | 99.3% |
| General and administrative expense (2) | 11,944 | 19,859 | (7,915) | (39.9)% |
| Depreciation and amortization | 18,936 | 11,151 | 7,785 | 69.8% |
| Loss on disposal of assets | 7,665 | 10,442 | (2,777) | (26.6)% |
| Interest expense | 1,261 | 5,175 | (3,914) | (75.6)% |
| Other expense (income) | 230 | (26) | (256) | (984.6)% |
| Income tax expense | 10,353 | 116 | 10,237 | 8,825.0% |
| Net income (loss) | $36,708 | $(24,351) | $61,059 | (250.7)% |
| ​ | ​ | ​ |  |  |
| Adjusted EBITDA (3) | $76,744 | $16,228 | $60,516 | 372.9% |
| Adjusted EBITDA Margin (3) | 19.9% | 9.4% | 10.5% | 111.7% |
| **Pressure pumping segment results of operations:** |  |  |  |  |
| Revenue | $375,045 | $163,840 | $211,205 | 128.9% |
| Cost of services | $290,470 | $143,372 | $147,098 | 102.6% |
| Adjusted EBITDA | $79,063 | $16,919 | $62,144 | 367.3% |
| Adjusted EBITDA Margin (4) | 21.1% | 10.3% | 10.8% | 104.9% |

(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.

### THREE MONTHS ENDED MARCH 31, 2018 COMPARED TO THREE MONTHS MARCH 31, 2017

*Revenues.* Revenues increased 124.1%, or $213.3 million, to $385.2 million for the three months ended March 31, 2018, as compared to $171.9 million for the three months ended March 31, 2017. The increase was primarily attributable to the increase in customer activity, fleet size 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 128.9%, or $211.2 million, for the three months ended March 31, 2018, as compared to the three months ended March 31, 2017. Revenues from services other than pressure pumping increased 25.7%, or $2.1 million, for the three months ended March 31, 2018 as compared to the three months ended March 31, 2017. The increase in revenues from services other than pressure pumping was primarily attributable to the increase in revenues and customer demand for our flowback, coil tubing and surface drilling services in the three months ended March 31, 2018.

*Cost of Services.* Cost of services increased 99.3%, or $148.6 million, to $298.1 million for the three months ended March 31, 2018, as compared to $149.6 million during the three months ended March 31, 2017. Cost of services in our pressure pumping segment increased $147.1 million for the three months ended March 31, 2018, as compared to the three months ended March 31, 2017. The increases were primarily attributable to higher activity levels, fleet size, 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 77.4% for the three months ended March 31, 2018, as compared to 87.5% for the three months ended March 31, 2017. The decrease in cost of services as a percentage of revenue for the pressure pumping segment resulted from a 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 three months ended March 31, 2018.

*General and Administrative Expenses.* General and administrative expenses decreased 39.9%, or $7.9 million, to $11.9 million for the three months ended March 31, 2018, as compared to $19.9 million for the three months ended March 31, 2017. The decrease was primarily attributable to nonrecurring stock compensation and IPO bonus, totaling $12.1 million, and was partially offset by a net increase in other remaining general and administrative expenses such as payroll, insurance and legal expenses of $4.2 million.

*Depreciation and Amortization.* Depreciation and amortization increased 69.8%, or $7.8 million, to $18.9 million for the three months ended March 31, 2018, as compared to $11.2 million for the three months ended March 31, 2017. The increase was primarily attributable to additional property and equipment purchased in part of 2017 and during the three months ended March 31, 2018. We calculate depreciation of property and equipment using the straight-line method.

*Loss on Disposal of Assets.* Loss on the disposal of assets decreased 26.6%, or $2.8 million, to $7.7 million for the three months ended March 31, 2018, as compared to $10.4 million for the three months ended March 31, 2017. The decrease was primarily attributable to improved efficiency in utilization of our equipment.

*Interest Expense.* Interest expense decreased 75.6%, or $3.9 million, to $1.3 million for the three months ended March 31, 2018, as compared to $5.2 million for the three months ended March 31, 2017. 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 in the first quarter of 2017.

*Other Expense.* Other expense was $0.2 million for the three months ended March 31, 2018, as compared to other income of $0.03 million for the three months ended March 31, 2017. The change is primarily attributable to the unrealized gain on the interest rate swap recorded during the three months ended March 31, 2017 compared to none recorded in the three months ended March 31, 2018.

*Income Tax Expense.* Total income tax expense was $10.4 million resulting in an effective tax rate of 22.0% for the three months ended March 31, 2018 as compared to $0.1 million and an effective tax rate of 0.5% for the three months ended March 31, 2017. The increase in income tax expense during the three months ended March 31, 2018 is primarily attributable to the increase in taxable income in 2018 compared to 2017.

### Liquidity and Capital Resources

On March 22, 2017, we completed our IPO 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 fleets and (iii) for general corporate purposes.

On March 22, 2017, we entered into a new revolving credit facility with a $150.0 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 receivable 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 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. In addition, the ABL Credit Facility includes a Springing Fixed Charge Coverage Ratio 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 and (ii) $12 million. The ABL has a commitment fee of 0.375%, which reduces to 0.25% if utilization is greater than 50% of the borrowing base.

On February 22, 2018, we entered into an amendment with our lenders to increase the capacity of the ABL Credit Facility. The amendment increased total capacity under the facility from $150 million to $200 million.

As of March 31, 2018, our cash and cash equivalents were $46.4 million, as compared to $23.9 million at December 31, 2017. Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility. Our primary uses of cash will be to continue to fund our operations, support growth opportunities and satisfy debt payments.

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.

### Cash and Cash Flows

The following table sets forth the historical cash flows for the three months ended March 31, 2018 and 2017 :

*($ in thousands)*

| Net cash provided by (used in): | Three Months Ended March 31, 2018 | 2017 |
| --- | ---: | ---: |
| Operating activities | $54,634 | $(3,394) |
| Investing activities | $(74,831) | $(50,458) |
| Financing activities | $42,661 | $5,881 |

### Operating Activities

Net cash provided by operating activities was $54.6 million for the three months ended March 31, 2018, compared to net cash used in operating activities of $3.4 million for the three months ended March 31, 2017. The net increase of $58.0 million was primarily due to increase in revenue and net income in the period, offset by our working capital needs resulting from higher fleet size and expanding activity levels.

### Investing Activities

Net cash used in investing activities increased to $74.8 million for the three months ended March 31, 2018, from $50.5 million for the three months ended March 31, 2017. The increase was primarily attributable to the additional hydraulic fracturing fleets and other ancillary equipment purchased and paid during the period, and a slight increase in maintenance capital expenditures, during the three months ended March 31, 2018, compared to the three months ended March 31, 2017.

### Financing Activities

Net cash provided by financing activities was $42.7 million for the three months ended March 31, 2018, and $5.9 million for the three months ended March 31, 2017. The net increase in cash provided by financing activities for the three months ended March 31, 2018 was primarily due to our borrowings under the ABL Credit Facility and equipment financing, totaling $46.7 million, partially offset by repayment of borrowings of $2.3 million, repayment of insurance financing of $1.4 million, and debt issuance cost of $0.4 million, during the three months ended March 31, 2018, compared to net cash used of $161.7 million for repayment of borrowings, repayment of insurance financing of $1.2 million, debt issuance cost of $1.6 million, IPO costs of $15.1 million, and offset by IPO proceeds of $185.5 million during the three months ended March 31, 2017.

### Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2018.

### Critical Accounting Policies and Estimates

There have been no material changes during the three months ended March 31, 2018 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.

### Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (ASU) No. 2014-09, *Revenue from Contracts with Customers (Topic 606)*. ASU No. 2014-09 requires entities to recognize revenue to depict transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 requires entities to disclose both qualitative and quantitative information that enables users of the consolidated financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including disclosure of significant judgments affecting the recognition of revenue. ASU No. 2014-09 was originally effective for annual periods beginning after December 15, 2016, using either the full retrospective or modified retrospective method. On August 12, 2015, the FASB issued ASU No. 2015-14, which defers the effective date of the revenue standard, ASU No. 2014-09, by one year for all entities and permits early adoption on a limited basis. We adopted ASU No. 2014-09 effective January 1, 2018, using the modified retrospective method. The adoption of this guidance had a nil impact on our prior period consolidated financial statements. This is because prior to the effective date of the new revenue guidance, substantially all of our performance obligations per our contracts with customers, except for hydraulic fracturing, were completed at a point-in-time and revenue recognized when control was transferred to the customers, which is consistent with ASU No. 2014-09. Our hydraulic fracturing segment performance obligation is satisfied over time. Prior to the effective date of the new revenue standards, our hydraulic fracturing segment revenue was recognized based on actual stages completed, i.e. using the output method, which faithfully depicts how our services are transferred over time to our customers, and is consistent with the requirements of the ASU No. 2014-09. Accordingly, no adjustments to our consolidated financial statements were required, other than the additional disclosures included as part of Note 1 in these condensed consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, *Leases*, a new standard on accounting for leases. The ASU introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in the current accounting guidance as well as the FASB’s new revenue recognition standard. However, the ASU eliminates the use of bright-line tests in determining lease classification as required in the current guidance. The ASU also requires additional qualitative disclosures along with specific quantitative disclosures to better enable users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The new standard is effective for annual reporting periods beginning after December 15, 2018, including periods within that reporting period, using a modified retrospective approach. Early adoption is permitted. We are currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU No. 2017-04, *Simplifying the Test for Goodwill Impairment*, which removes the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test. As a result, under this ASU, an entity would recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. This pronouncement is effective for impairment tests in fiscal years beginning after December 15, 2019, on a prospective basis. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We believe that the adoption of this guidance will not materially affect our consolidated financial statements.

### 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 close to the end of 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, beginning in the third quarter of 2016, oil prices started signs of recovery and reaching an average of over $60 per barrel in April of 2018. 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, 272 characters.

As of March 31, 2018, 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 of Market Risk” in our Form 10-K.

## Controls and procedures

As filed, 1,721 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, principal financial officer and principal accounting 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, principal financial officer and principal accounting 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, principal financial officer and principal accounting officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2018.

#### Changes in Internal Control 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, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

## Risk factors

As filed, 277 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 Form 10-K, which is accessible on the SEC’s website at *www.sec.gov.*

Filed May 9, 2018.
Source: SEC EDGAR, the filing index for accession 0001680247-18-000044. Last ingested by Listed: Nov 2, 2026, 18:28 ET. No prices; not investment advice.