UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________
FORM 10-K
______________________________
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 001-38035
______________________________
ProPetro Holding Corp.
(Exact name of registrant as specified in its charter)
______________________________
Delaware
26-3685382
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
1706 South Midkiff, Bldg. B
Midland, Texas 79701
(Address of principal executive offices)
Registrant’s telephone number, including area code: (432) 688-0012

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock ($0.001 par value)
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: 
None
______________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ý  No ¨   
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý  No  ¨ 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
ý 
 
Accelerated filer
o
Non-accelerated filer
 
o(Do not check if a smaller reporting company)
 
Smaller reporting company
o
 
 
 
 
Emerging growth company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
The aggregate market value of the Company’s Common Stock held by nonaffiliates on June 30, 2018, determined using the per share closing price on the New York Stock Exchange Composite tape of $15.68 on that date, was approximately $838.7 million.
The number of the registrant’s common shares, par value $0.001 per share, outstanding at February 18, 2019, was 100,257,626.




TABLE OF CONTENTS
 
 
 
 




FORWARD‑LOOKING STATEMENTS
This annual report on Form 10-K contains forward‑looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “may,” “could,” “plan,” “project,” “budget,” “predict,” “pursue,” “target,” “seek,” “objective,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” and other expressions that are predictions of, or indicate, future events and trends and that do not relate to historical matters identify forward‑looking statements. Our forward‑looking statements include, among other matters, statements about our business strategy, industry, future profitability, expected capital expenditures and the impact of such expenditures on our performance and capital programs.
A forward‑looking statement may include a statement of the assumptions or bases underlying the forward‑looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. You are cautioned not to place undue reliance on any forward‑looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward‑looking statements include:
•    the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of     crude oil, natural gas, natural gas liquids and other hydrocarbons;
•    changes in general economic and geopolitical conditions;
•    competitive conditions in our industry;
•    changes in the long‑term supply of and demand for oil and natural gas;
•    actions taken by our customers, suppliers, competitors and third‑party operators;
•    changes in the availability and cost of capital;
•    our ability to successfully implement our business plan;
•    large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;
•    the price and availability of debt and equity financing (including changes in interest rates);
•    our ability to complete growth projects on time and on budget;
•    changes in our tax status;
•    technological changes;
•    operating hazards, natural disasters, weather‑related delays, casualty losses and other matters beyond our     control;
•    the effects of existing and future laws and governmental regulations (or the interpretation thereof); and
•    the effects of future litigation.
You should not place undue reliance on our forward‑looking statements. Although forward‑looking statements reflect our good faith beliefs at the time they are made, forward‑looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors,” which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward‑looking statements. We undertake no obligation to publicly update or revise any forward‑looking statement, whether as a result of new information, future events, changed circumstances or otherwise, unless required by law.
Unless the context indicates otherwise, all references to “we,” “our” or “us” refer to ProPetro Holding Corp. and its consolidated subsidiary, ProPetro Services, Inc.

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PART I
Item 1.     Business.
Our Company
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, or 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 one of the leading providers of hydraulic fracturing services in the region by hydraulic horsepower, or HHP. During the year ended December 31, 2018, we purchased and deployed four newbuild hydraulic fracturing units, bringing our total horse power to 905,000 HHP, or 20 deployed fleets.
On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer Natural Resources USA, Inc. (“Pioneer”) and Pioneer Natural Resources Pumping Services, LLC (“Pioneer Pumping Services”). Prior to the purchase, the pressure pumping assets exclusively provided integrated pressure pumping services to Pioneer’s completion and production operations. The acquisition cost of the assets was comprised of $110.0 million of cash and 16.6 million shares of our common stock. In connection with the consummation of transaction, we became a strategic long-term service provider to Pioneer, providing pressure pumping and related services for a term of up to 10 years.
The pressure pumping assets acquired include eight hydraulic fracturing fleets with a total of 510,000 HHP, four coiled tubing units and an associated equipment maintenance facility. Through this acquisition, we expanded our existing presence in the Permian Basin, and increased our pumping capacity by 56%, to 28 hydraulic fracturing fleets with a total of 1,415,000 HHP, further strengthening our position as one of the largest pure-play provider of integrated well completion services in the Permian Basin.
Our modern hydraulic fracturing fleet has been designed to handle the most challenging Permian Basin 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.
In addition to our core hydraulic fracturing operations, we also offer a suite of complementary well completion and production services, including cementing, coiled tubing, flowback services and 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 an unconventional well.
Our primary business objective is to serve as a strategic long-term partner to our customers. We achieve this objective by providing reliable, high‑quality services that are tailored to our customers’ needs and synchronized with their well development programs. This alignment assists our customers in optimizing the long‑term development of their unconventional resources. Over the past three years, we have leveraged our strong relationships in the Permian Basin to significantly grow our installed HHP capacity and organically build our cementing and coiled tubing lines of business. Consistent with past performance, we believe our substantial market presence will continue to yield a variety of actionable growth opportunities allowing us to expand both our hydraulic fracturing and complementary services going forward. To this end, we intend to continue to differentiate ourselves, consistent with our past practice, by opportunistically deploying new equipment on a long‑term dedicated basis.
Our Services
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. For additional financial information on our reportable segment, please see Part II - Item 8. Financial Statements and Supplementary Data.

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Pressure Pumping
Hydraulic Fracturing
We primarily provide hydraulic fracturing services to E&P companies in the Permian Basin. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. We have significant expertise in multi‑stage fracturing of horizontal oil‑producing wells in unconventional geological formations. During the year ended December 31, 2018, we continued to organically grow our hydraulic fracturing business to a total of 20 hydraulic fracturing fleets with an aggregate of 905,000 HHP. Following the consummation of our acquisition of pressure pumping assets from Pioneer Pressure Pumping Services, we increased our hydraulic fracturing business to a total 28 fleets, or 1,415,000 HHP.
The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, which in our business are comprised primarily of sand, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return of hydrocarbons for the operator.
We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also refer to all of our fracturing units, other equipment and vehicles necessary to perform a fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” Each hydraulic fracturing unit consist primarily of a high pressure hydraulic pump, diesel engine, transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted to a flatbed trailer.
We provide dedicated equipment, personnel and services that are tailored to meet each of our customer’s needs. Each fleet has a designated team of personnel, which allows us to provide responsive and customized services, such as project design, proppant and other consumables procurement, real‑time data provision and post‑completion analysis for each of our jobs. Many of our hydraulic fracturing fleets and associated personnel have continuously worked with the same customer for the past several years promoting deep relationships and a high degree of coordination and visibility into future customer activity levels. Furthermore, in light of our substantial market presence and historically high fleet utilization levels, we have established a variety of entrenched relationships with key equipment, sand and other downhole consumable suppliers, including over 30 sand suppliers utilized in 2018. These strategic relationships ensure ready access to equipment, parts and materials on a timely and economic basis and allow our dedicated procurement logistics team to ensure consistently safe and reliable operations.
Cementing
We provide cementing services for completion of new wells and remedial work on existing wells. Cementing services use pressure pumping equipment to deliver a slurry of liquid cement that is pumped down a well between the casing and the borehole. Cementing provides isolation between fluid zones behind the casing to minimize potential damage to hydrocarbon bearing formations or the integrity of freshwater aquifers, and provides structural integrity for the casing by securing it to the earth. Cementing is also done when recompleting wells, where one zone is plugged and another is opened.
As of December 31, 2018, we operated a total of 20 cementing units, with 13 units operating in the Permian Basin and 7 units operating in the Uinta‑Piceance Basin. We believe that our cementing segment provides an organic growth opportunity for us to expand our service offerings within our existing customer base.

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Other Services
Coiled Tubing
Coiled tubing services involve injecting coiled tubing into wells to perform various completion well intervention operations. Coiled tubing is a flexible steel pipe with a diameter of typically less than three inches and manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck‑mounted reel for onshore applications. Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services to enhance the flow of oil or natural gas.
The principal advantages of using coiled tubing include the ability to (i) continue production from the well without interruption, thus reducing the risk of formation damage, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe used with a workover rig, which must be jointed and unjointed, (iii) direct fluids into a wellbore with more precision, allowing for improved stimulation fluid placement, (iv) provide a source of energy to power a downhole motor or manipulate down‑hole tools and (v) enhance access to remote fields due to the smaller size and mobility.
As of December 31, 2018, we had 8 coiled tubing units of various sizes. We believe these units are well suited for the performance requirements of the unconventional resource markets we serve.
Flowback Services
Our flowback services consist of production testing, solids control, hydrostatic testing and torque services. Flowback involves the process of allowing fluids to flow from the well following a treatment, either in preparation for an impending phase of treatment or to return the well to production. Our flowback equipment consists of manifolds, accumulators, valves, flare stacks and other associated equipment that combine to form up to a total of five well‑testing spreads. We provide flowback services in the Permian Basin and mid‑continent markets.
Surface Air Drilling
We operated a surface air drilling operation in the Uinta‑Piceance Basin, which offered pre‑set surface air drilling services to target depths of approximately 4,000 feet in areas of fragile geology. Air drilling is a technique in which oil, natural gas, or geothermal wells are drilled by creating a pressure within the well that is lower than the reservoir pressure, which results in increased rates of penetration, reduced formation damage and reduced drilling costs.
On August 31, 2018, we divested our surface air drilling operations, included in our "all other" operating segment category in our financial statements, in order to continue to position ourselves as a Permian Basin-focused pressure pumping business because we believe the pressure pumping market in the Permian Basin offers more supportive long-term growth fundamentals. The divestiture of our surface air drilling operations did not qualify for presentation and disclosure as discontinued operations, and accordingly we have recorded the resulting loss on disposal of our surface air drilling of $0.3 million, as part of our loss on disposal of asset in our statement of operations included in this annual report. The divestiture of our surface air drilling operations resulted in a reduction in the number of our current operating segments. The change in the number of our operating segments did not impact our reportable segment information reported in the financial statements included in this annual report.
Competitive Strengths
Our primary business objective is to serve as a strategic long-term partner for our customers. We achieve this objective by providing reliable, high‑quality services that are tailored to our customers’ needs and synchronized with their well development programs. This alignment assists our customers in optimizing the long‑term development of their unconventional resources. We believe that the following competitive strengths differentiate us from our peers and uniquely position us to achieve our primary business objective.

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Strong market position in the Permian Basin. We believe we are one of the largest hydraulic fracturing provider by HHP in the Permian Basin, which is the most prolific oil producing area in the United States. Our longstanding customer relationships and substantial Permian Basin market presence uniquely position us to continue growing in tandem with the basin’s ongoing development. The Permian Basin is a mature, liquids‑rich basin with well known geology and a large, exploitable resource base that delivers attractive E&P producer economics at or below current commodity prices. As a result of its significant size, coupled with the presence of multiple prospective geologic benches and other favorable characteristics, the Permian Basin has become widely recognized as the most attractive and economic oil resource in North America.
Our operational focus has historically been in the Permian Basin’s Midland sub‑basin in support of our customers’ core operations. More recently, however, many of our customers have made sizeable acquisitions in the Delaware Basin, and we have expanded our services into the Delaware Basin to help develop their acreage. Further, we believe that we are uniquely positioned to capture a large addressable growth opportunity as the basin develops. For the foreseeable future, we expect both the Midland Basin and the Delaware Basin to continue to command a disproportionate share of future North American E&P spending.
Hydraulic fracturing is highly levered to increasing drilling activity and completion intensity levels. The combination of an expanding Permian Basin horizontal rig count and more complex well completions has a compounding effect on HHP demand growth. Horizontal drilling has become the default method for E&P operators to most economically extract unconventional resources, and the number of horizontal rigs has increased from 22% of the total Permian Basin rig count in December 2011 to approximately 91% of the Permian Basin rig count at December 31, 2018. As the horizontal rig count has grown, well completion intensity levels have also increased as a result of longer wellbore lateral lengths, more fracturing stages per foot of lateral and increasing amounts of proppant per stage. Furthermore, the ongoing improvement in drilling and completion efficiencies, driven by innovations such as multi‑well pads and zipper fracs, have further increased the demand for HHP. Taken together, these demand drivers have helped contribute to the full utilization of our fleet and have us well positioned to capture future growth opportunities and enhanced pricing for our services.
Deep relationships and operational alignment with high‑quality, Permian Basin‑focused customers. Our deep local roots, operational expertise and commitment to safe and reliable service have allowed us to cultivate longstanding customer relationships with the most active and well‑capitalized Permian Basin operators. Many of our current customers have worked with us since our inception and have integrated our fleet scheduling with their well development programs. This high degree of operational alignment and their continued support have allowed us to maintain relatively high utilization rates over time. As our customers increase activity levels, we expect to continue to leverage these strong relationships to keep our fleet fully utilized and selectively expand our platform in response to specific customer demand.
Standardized fleet of modern, well‑maintained equipment. We have a large, homogenous fleet of modern equipment that is configured to handle the Permian Basin’s most complex, highest‑intensity, hydraulic fracturing jobs. We believe that our fleet design is a key advantage compared to many of our competitors who have fracturing units that are not optimized for Permian Basin conditions. Our fleet is largely standardized across units to facilitate efficient maintenance and repair, reducing equipment downtime and improving labor efficiency. Furthermore, our strong relationships with a variety of key suppliers and vendors provide us with the reliable access to the equipment necessary to support our continued organic growth strategy.
Proven cross‑cycle financial performance. Over the past several years, we have maintained high cross‑cycle fleet utilization rates. Since September 2016 our fleet has consistently recorded a utilization rate of approximately 100%. Our consistent track record of steady growth, coupled with our ability to quickly deploy new HHP on a dedicated and fully utilized basis, has resulted in revenue growth across the industry’s cycles. We believe that we will be able to continue to grow faster than our competitors while preserving attractive EBITDA margins as a result of our differentiated service offerings and a robust backlog of demand for our services. Furthermore, we believe that our philosophy of maintaining modest

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financial leverage and a healthy balance sheet has left us more conservatively capitalized than our peers. We expect that improving market fundamentals, our superior execution and our customer‑focused approach should result in strong financial performance.
Seasoned management and operating team. We have a seasoned executive management team, with our senior members contributing more than 100 years of collective industry and financial experience. Members of our management team founded our business and seeded our company with a portion of our original investment capital. We believe their track record of successfully building premier oilfield service companies in the Permian Basin, as well as their deep roots and relationships throughout the West Texas community, provide a meaningful competitive advantage for our business. In addition, our management team has assembled a loyal group of highly‑motivated and talented managers and field personnel, and we have had minimal manager‑level turnover in our core service divisions over the past three years. We employ a balanced decision‑making structure that empowers managerial and field personnel to work directly with customers to develop solutions while leveraging senior management’s oversight. This collaborative approach fosters strong customer links at all levels of the organization and effectively institutionalizes customer relationships beyond the executive suite.
Strategy
Our strategy is to:
Capture an increasing share of rising demand for hydraulic fracturing services in the Permian Basin. We intend to continue to position ourselves as a Permian Basin‑focused hydraulic fracturing business, as we believe the Permian Basin hydraulic fracturing market offers supportive long‑term growth fundamentals. These fundamentals are characterized by increased demand for our HHP, driven by increasing drilling activity and well completion intensity levels. We are currently operating at approximately 100% utilization, and we believe we are strategically positioned to deploy additional hydraulic fracturing equipment as our customers continue to develop their assets in the Midland Basin and Delaware Basin.
Capitalize on improving efficiency gains. We intend to continue to work with our customers and vendors to improve our operational efficiencies and enhance our margins. We believe that improving our efficiencies will result in greater revenue and enhanced margins as fixed costs are spread over a broader revenue base.
Cross‑sell our complementary services. In addition to our hydraulic fracturing services, we offer a broad range of complementary services in support of our customers’ development activities, including cementing, coiled tubing, flowback services and drilling. These complementary services create operational efficiencies for our customers, and allow us to capture a greater percentage of their capital spending across the lifecycle of an unconventional well. We believe that, as our customers increase spending levels, we are well positioned to continue cross‑selling and growing our complementary service offerings.
Maintain financial stability and flexibility to pursue growth opportunities. Consistent with our historical practices, we plan to continue to maintain a conservative balance sheet, which will allow us to better react to potential changes in industry and market conditions and opportunistically grow our business. In the near term, we intend to continue our past practice of aligning our growth capital expenditures with visible customer demand by strategically deploying new equipment on a long‑term, dedicated basis in response to inbound customer requests. We will also selectively evaluate potential strategic acquisitions that increase our scale and capabilities or diversify our operations.
Our Customers
Our customers consist primarily of oil and natural gas producers in North America. Our top five customers accounted for approximately 68.7%, 66.0% and 58.0% of our revenue, for the years ended December 31, 2018, 2017 and 2016, respectively. For the year ended December 31, 2018, XTO Energy, Parsley Energy Operations, LLC and

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CrownQuest Operating, LLC, accounted for 24.1%, 16.5%, and 12.2%, respectively, of total revenue. No other customer accounted for more than 10% of total revenue for the year ended December 31, 2018.
Competition
The markets in which we operate are highly competitive. To be successful, an oilfield services company must provide services that meet the specific needs of oil and natural gas exploration and production companies at competitive prices. Competitive factors impacting sales of our services are price, reputation, 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, equipment’s ability to handle the most complex Permian Basin well completions, and commitment to safety and reliability.
We provide our services primarily in the Permian Basin, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies. Our major competitors for hydraulic fracturing services include C&J Energy Services, Halliburton, Patterson‑UTI Energy Inc., RPC, Inc., Schlumberger, Keane Group, Inc., Liberty Oilfield Services, FTS International, Inc., Superior Energy Services and a number of locally oriented businesses.
Seasonality
Our results of operations have historically reflected seasonal tendencies, generally in the fourth quarter, relating to the conclusion of our customers’ annual capital expenditure budgets, the holidays and inclement winter weather during which we may experience declines in our operating results.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the oilfield services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause personal injury or loss of life, damage or destruction of property, equipment, natural resources and the environment and suspension of operations.
In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.
Our business involves the transportation of heavy equipment and materials, and as a result, we may also experience traffic accidents which may result in spills, property damage and personal injury.
Despite our efforts to maintain safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.
We maintain commercial general liability, workers’ compensation, business auto, commercial property, umbrella liability, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. Further, we have pollution legal liability coverage for our business entities, which would cover, among other things, third party liability and costs of clean up relating to environmental contamination on our premises while our equipment is in transit and on our customers’ job site. With respect to our hydraulic fracturing operations, coverage would be available under our pollution legal liability policy

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for any surface or subsurface environmental clean‑up and liability to third parties arising from any surface or subsurface contamination. We also have certain specific coverages for some of our businesses, including our hydraulic fracturing services.
Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See “Risk Factors” for a description of certain risks associated with our insurance policies.
Environmental and Occupational Health and Safety Regulations
Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, and occupational health and safety. Numerous federal, state and local governmental agencies issue regulations that often require difficult and costly compliance measures that could carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non compliance. These laws and regulations may, for example, restrict the types, quantities and concentrations of various substances that can be released into the environment, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, or require action to prevent or remediate pollution from current or former operations. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental, health and safety laws and regulations occur frequently, and any changes that result in more stringent and costly requirements could materially adversely affect our operations and financial position. We have not experienced any material adverse effect from compliance with these requirements, however, this trend may not continue in the future.
Below is an overview of some of the more significant environmental, health and safety requirements with which we must comply. Our customers’ operations are subject to similar laws and regulations. Any material adverse effect of these laws and regulations on our customers’ operations and financial position may also have an indirect material adverse effect on our operations and financial position.
Waste Handling. We handle, transport, store and dispose of wastes that are subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable state laws and regulations, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non hazardous waste provisions.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non hazardous wastes or recategorize some non hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to recategorize certain oil and natural gas exploration, development and production wastes as hazardous wastes. Several environmental organizations have also petitioned the EPA to modify existing regulations to recategorize certain oil and natural gas exploration, development and production wastes as hazardous. Any such changes in these laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

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Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”) and analogous state laws generally impose liability without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Liability for the costs of removing or remediating previously disposed wastes or contamination, damages to natural resources, the costs of conducting certain health studies, amongst other things, is strict and joint and several. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state laws. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such hazardous substances have been released.
One of our facilities in Midland, Texas is located within the boundaries of the West County Road 112 federal Superfund site, which site and the associated investigation and cleanup is being managed by EPA Region 6. The site’s soil and groundwater is contaminated with chromium and hexavalent chromium as a result of historic site operations unaffiliated with the Company and unassociated with the Company’s operations. Toxic tort claims also have been asserted as a result of this groundwater contamination against various unaffiliated parties. In 2013, in order to reduce the Company’s risk of incurring any future liabilities in connection with this site, the Company negotiated and obtained a bona fide prospective purchaser (“BFPP”) letter from EPA Region 6 in connection with a reorganization of the facility site ownership and lease. The BFPP letter generally acknowledges and provides that the Company is unaffiliated with any potentially responsible parties or known contamination that is the subject of the Superfund action, the Company agrees to comply with any future land use restrictions that may be imposed in connection with a site remedy (none have been imposed to date), and the Company agrees to cooperate with and provide access and assistance to EPA Region 6 in connection with the remediation. In exchange for these undertakings, the Company will not be subject to any CERCLA action by the EPA. In addition, the Company separately obtained a 10‑year environmental pollution legal liability insurance policy, effective March 4, 2013, with an aggregate limit of $20 million to insure against potential third‑party claims and any known or unknown pre‑existing conditions at the site, including Superfund or toxic tort liabilities. Both prior to and since obtaining the BFPP letter and the insurance policy, no claims have been made or threatened against the Company or any of its affiliated persons or entities with regard to this Superfund site or any related liabilities, and the Company has not incurred any significant expenses in connection with this matter.
NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials (“NORM”) associated with oil and gas deposits and, accordingly may result in the generation of wastes and other materials containing NORM. NORM exhibiting levels of radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements.
Water Discharges. The Clean Water Act, Safe Drinking Water Act, Oil Pollution Act and analogous state laws and regulations impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Also, spill prevention, control and countermeasure plan requirements require appropriate containment berms and similar structures to help prevent the contamination of regulated waters.
Air Emissions. The Clean Air Act (“CAA”) and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other emissions control requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants from specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.

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Climate Change. The EPA has determined that greenhouse gases (“GHGs”) present an endangerment to public health and the environment because such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented, and continues to adopt and implement, regulations that restrict emissions of GHGs under existing provisions of the CAA. The EPA also requires the annual reporting of GHG emissions from certain large sources of GHG emissions in the United States, including certain oil and gas production facilities. The U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one‑half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement entered into force in November 2016. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four‑year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
Moreover, climate change may cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.
Endangered and Threatened Species. Environmental laws such as the Endangered Species Act (“ESA”) and analogous state laws may impact exploration, development and production activities in areas where we operate. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and various state analogs. The U.S. Fish and Wildlife Service may identify previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us or our customers to incur additional costs or become subject to operating restrictions or operating bans in the affected areas.
Regulation of Hydraulic Fracturing and Related Activities. Our hydraulic fracturing operations are a significant component of our business. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Beginning in August 2012, the EPA issued a series of rules under the CAA that establish new emission control requirements for certain oil and natural gas production and natural gas processing operations and associated equipment. After several attempts to delay implementation, in September 2018 the EPA issued a proposal to amend and reduce such requirements. In March 2015, the Bureau of Land Management (“BLM”) finalized a rule governing hydraulic fracturing on federal lands. In June 2016, a federal district court judge in Wyoming struck down the final rule, finding that the BLM lacked congressional authority to promulgate the rule. However, in July 2017, the BLM initiated a rulemaking to rescind the final rule and reinstate the regulations that existed immediately before the published effective date of the rule. In light of the BLM’s proposed rulemaking, in September 2017, the U.S. Court of Appeals for the Tenth Circuit dismissed the appeal and remanded with directions to vacate the lower court’s opinion, leaving the final rule in place. The BLM initiated a rulemaking to rescind the final rule in December 2017. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several

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states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.
More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. The United States Geological Survey also noted the potential for induced seismicity in Ohio and Alabama. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission released well completion seismicity guidelines in December 2016 for operators in the SCOOP and STACK that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, in February 2017, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission adopted similar rules in 2014. In addition, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters, and disposal or storage of fracturing wastewater in unlined pits. The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations.
Increased regulation of hydraulic fracturing and related activities (whether as a result of the EPA study results or resulting from other factors) could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and record keeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.
OSHA Matters. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.
Employees
As of December 31, 2018, we employed 1,579 people. None of our employees are represented by labor unions or subject to collective bargaining agreements.
We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SEC’s web site at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room in Washington, D.C. Please call the SEC at 1-800-SEC-0330 for further information on their public reference room. Our SEC filings are also available to the public on our website at www.propetroservices.com. Please note that information contained on our website, whether currently posted or posted in the future, is not a part of this Annual Report on Form 10-K or the documents incorporated by reference in this Annual Report on Form 10-K. This Annual Report on Form 10-K also contains summaries of the terms of certain agreements that we have entered into that are filed as exhibits to this Annual Report on Form 10-K or other reports that we have filed with the SEC. The descriptions contained in this Annual Report on Form 10-K of

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those agreements do not purport to be complete and are subject to, and qualified in their entirety by reference to, the definitive agreements. You may request a copy of the agreements described herein at no cost by writing or telephoning us at the following address: ProPetro Holding Corp., Attention: Investor Relations, P.O. Box 873, Midland, Texas 79702, phone number (432) 688-0012.

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Item 1A.    Risk Factors.
The following is a description of significant factors that could cause actual results to differ materially from those contained in forward-looking statement made in this Annual Report on Form 10-K and presented elsewhere by management from time to time. Such factors may have a material adverse effect on our business, financial condition and results of operations. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all our potential risks or uncertainties. Due to these, and other factors, past performance should not be considered an indication of future performance.
Our business and financial performance depends on the oil and natural gas industry and particularly on the level of capital spending and exploration and production activity within the United States and in the Permian Basin, and a decline in prices for oil and natural gas may have an adverse effect on our revenue, cash flows, profitability and growth.
Demand for most of our services depends substantially on the level of capital expenditures in the Permian Basin by companies in the oil and natural gas industry. As a result, our operations are dependent on the levels of capital spending and activity in oil and gas exploration, development and production. A prolonged reduction in oil and gas prices would generally depress the level of oil and natural gas exploration, development, production, and well completion activity and would result in a corresponding decline in the demand for the hydraulic fracturing services that we provide. The significant decline in oil and natural gas prices during 2015 and 2016 caused a reduction in our customers’ spending and associated drilling and completion activities, which had an adverse effect on our revenue. If prices were to decline, similar declines in our customers’ spending would have an adverse effect on our revenue. In addition, a worsening of these conditions may result in a material adverse impact on certain of our customers’ liquidity and financial position resulting in further spending reductions, delays in the collection of amounts owing to us and similar impacts.
Many factors over which we have no control affect the supply of, and demand for, and our customers’ willingness to explore, develop and produce oil and natural gas, and therefore, influence prices for our services, including:
the domestic and foreign supply of, and demand for, oil and natural gas;
the level of prices, and expectations about future prices, of oil and natural gas;
the level of global oil and natural gas exploration and production;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the supply of and demand for drilling and hydraulic fracturing equipment;
the expected decline rates of current production;
the price and quantity of foreign imports;
political and economic conditions in oil and natural gas producing countries and regions, including the United States, the Middle East, Africa, South America and Russia;
actions by the members of Organization of Petroleum Exporting Countries with respect to oil production levels and announcements of potential changes in such levels;
speculative trading in crude oil and natural gas derivative contracts;
the level of consumer product demand;
the discovery rates of new oil and natural gas reserves;
contractions in the credit market;

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the strength or weakness of the U.S. dollar;
available pipeline and other transportation capacity;
the levels of oil and natural gas storage;
weather conditions and other natural disasters;
domestic and foreign tax policy;
domestic and foreign governmental approvals and regulatory requirements and conditions;
the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;
technical advances affecting energy consumption;
the proximity and capacity of oil and natural gas pipelines and other transportation facilities;
the price and availability of alternative fuels;
the ability of oil and natural gas producers to raise equity capital and debt financing;
merger and divestiture activity among oil and natural gas producers; and
overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Such a decline would have a material adverse effect on our business, results of operation and financial condition.
The cyclical nature of the oil and natural gas industry may cause our operating results to fluctuate.
We derive our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We have experienced, and may in the future experience, significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, prolonged low commodity prices experienced by the oil and natural gas industry during 2015 and 2016, combined with adverse changes in the capital and credit markets, caused many exploration and production companies to reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (for example, a day, a week or a month) for the actual period of time the service is provided to our customers. By contracting services on a short‑term basis, we are exposed to the risks of a rapid reduction in market prices and utilization and resulting volatility in our revenues.
The majority of our operations are located in the Permian Basin, making us vulnerable to risks associated with operating in one major geographic area.
Our operations are geographically concentrated in the Permian Basin. For the years ended December 31, 2018, 2017 and 2016, approximately 99%, 97% and 97%, respectively, of our revenues were attributable to our operations in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in the Permian Basin caused by significant governmental regulation, processing or transportation capacity constraints, market limitations, curtailment of production or interruption of the processing or transportation of oil and natural gas produced from the wells in these areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these

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conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our operations, we could experience any of the same conditions at the same time, resulting in a relatively greater impact on our revenue than they might have on other companies that have more geographically diverse operations.
We are exposed to the credit risk of our customers, and any material nonpayment or nonperformance by our customers could adversely affect our business, results of operations and financial condition.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re‑market or otherwise use the production could have a material adverse effect on our business, results of operations and financial condition. The depressed oil and natural gas prices in 2015 and 2016 negatively impacted the financial condition and liquidity of our customers, and future declines, sustained lower prices, or continued volatility could impact their ability to meet their financial obligations to us.
We face significant competition that may cause us to lose market share.
The oilfield services industry is highly competitive and has relatively few barriers to entry. The principal competitive factors impacting sales of our services are price, reputation and technical expertise, equipment and service quality and health and safety standards. The market is also fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. For instance, our larger competitors may offer services at below‑market prices or bundle ancillary services at no additional cost to our customers. We compete with large national and multi‑national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis.
Some jobs are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. The amount of equipment available may exceed demand, which could result in active price competition. In addition, depressed commodity prices lower demand for hydraulic fracturing equipment, which results in excess equipment and lower utilization rates. In addition, some exploration and production companies have commenced completing their wells using their own hydraulic fracturing equipment and personnel. Any increase in the development and utilization of in‑house fracturing capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.
Furthermore, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. We cannot assure that we will be able to maintain our competitive position.
New technology may cause us to become less competitive.
The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent or other intellectual property protections. Although we believe our equipment and processes currently give us a competitive advantage, as competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to develop, implement or acquire certain new

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technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and develop and implement new products on a timely basis or at an acceptable cost. We cannot be certain that we will be able to develop and implement new technologies or products on a timely basis or at an acceptable cost. Limits on our ability to develop, effectively use and implement new and emerging technologies could have a material adverse effect on our business, financial condition, prospects or results of operations.
Our business depends upon our ability to obtain specialized equipment, parts and key raw materials, including frac sand and chemicals, from third‑party suppliers, and we may be vulnerable to delayed deliveries and future price increases.
We purchase specialized equipment, parts and raw materials (including, for example, frac sand, chemicals and fluid ends) from third party suppliers and affiliates. At times during the business cycle, there is a high demand for hydraulic fracturing and other oil field services and extended lead times to obtain equipment and raw materials needed to provide these services. Should our current suppliers be unable or unwilling to provide the necessary equipment, parts or raw materials or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, future price increases for this type of equipment, parts and raw materials could negatively impact our ability to purchase new equipment, to update or expand our existing fleet, to timely repair equipment in our existing fleet or meet the current demands of our customers.
Reliance upon a few large customers may adversely affect our revenue and operating results.
The majority of our revenue is generated from our hydraulic fracturing services. Due to the large percentage of our revenue historically derived from our hydraulic fracturing services with recurring customers and the limited availability of our fracturing units, we have had some degree of customer concentration. Our top ten customers represented approximately 85.5%, 87.0% and 83.0% of our consolidated revenue for the years ended December 31, 2018, 2017 and 2016, respectively. It is likely that we will depend on a relatively small number of customers for a significant portion of our revenue in the future. If a major customer fails to pay us, revenue would be impacted and our operating results and financial condition could be harmed. Additionally, if we were to lose any material customer, we may not be able to redeploy our equipment at similar utilization or pricing levels and such loss could have an adverse effect on our business until the equipment is redeployed at similar utilization or pricing levels.
Certain of our completion services, particularly our hydraulic fracturing services, are substantially dependent on the availability of water. Restrictions on our or our customers’ ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of unconventional shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Over the past several years, certain of the areas in which we and our customers operate have experienced extreme drought conditions and competition for water in such areas is growing. In addition, some state and local governmental authorities have begun to monitor or restrict the use of water subject to their jurisdiction for hydraulic fracturing to ensure adequate local water supply. For instance, some states require E&P companies to report certain information regarding the water they use for hydraulic fracturing and to monitor the quality of groundwater surrounding some wells stimulated by hydraulic fracturing. Generally, our water requirements are met by our customers from sources on or near their sites, but there is no assurance that our customers will be able to obtain a sufficient supply of water from sources in these areas. Our or our customers’ inability to obtain water from local sources or to effectively utilize flowback water could have an adverse effect on our financial condition, results of operations and cash flows.
We rely on a few key employees whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, such as our Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, Chief Accounting Officer and General Counsel could disrupt our operations. We do not maintain “key person” life

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insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.
The delivery of our services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited. As a result, competition for experienced oilfield service personnel is intense, and we face significant challenges in competing for crews and management with large and well‑established competitors. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, or at all, which could limit our ability to grow.
The oilfield services industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures incurred were approximately $592.6 million, $305.3 million and $46.0 million during the years ended December 31, 2018, 2017 and 2016. We have historically financed capital expenditures primarily with funding from cash on hand, cash flow from operations, equipment and vendor financing and borrowings under our credit facilities. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment or properly maintaining our existing equipment. Further, any disruptions or continuing volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, geopolitical issues, interest rates, inflation, the availability and cost of credit and the United States and foreign financial markets have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have precipitated an economic slowdown. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and adversely impact our results of operations, liquidity and financial condition.

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Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.
Our existing and future indebtedness, whether incurred in connection with acquisitions, operations or otherwise, may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:
increasing our vulnerability to general adverse economic and industry conditions;
the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
any failure to comply with the financial or other debt covenants, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;
our level of debt could impair our ability to obtain additional financing, or obtain additional financing on favorable terms, in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and
our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.
Restrictions in our ABL Credit Facility (as defined herein) and any future financing agreements may limit our ability to finance future operations or capital needs or capitalize on potential acquisitions and other business opportunities.
The operating and financial restrictions and covenants in our credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our ABL Credit Facility restricts or limits our ability to:
grant liens;
incur additional indebtedness;
engage in a merger, consolidation or dissolution;
enter into transactions with affiliates;
sell or otherwise dispose of assets, businesses and operations;
materially alter the character of our business as currently conducted; and
make acquisitions, investments and capital expenditures.
Furthermore, our ABL Credit Facility contains certain other operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the ABL Credit Facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our ABL Credit Facility, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our ABL Credit Facility or any new indebtedness could have similar or greater restrictions. Please

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read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility and Other Financing Arrangements .”
We may become more leveraged and our indebtedness could adversely affect our operations and financial condition.
Our business is capital intensive and we may seek to raise debt capital to fund our business and growth strategy. Indebtedness could have negative consequences that could materially and adversely affect our business, financial condition, results of operations, cash flows and prospects, such as:
requiring us to dedicate a substantial portion of our cash flow from operating activities to payments on our indebtedness, thereby reducing the availability of cash flow to fund working capital, capital expenditures, research and development efforts, potential strategic acquisitions and other general corporate purposes;
limiting our ability to obtain additional financing to fund growth, working capital or capital expenditures, or to fulfill debt service requirements or other cash requirements;
increasing our vulnerability to economic downturns and changing market conditions;
placing us at a competitive disadvantage relative to competitors that have less debt; and
to the extent that our debt is subject to floating interest rates, increasing our vulnerability to fluctuations in market interest rates.
Our operations are subject to unforeseen interruptions and hazards inherent in the oil and natural gas industry, for which we may not be adequately insured and which could cause us to lose customers and substantial revenue.
Our operations are exposed to the risks inherent to our industry, such as equipment defects, vehicle accidents, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards, such as oil spills and releases of, and exposure to, hazardous substances. For example, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. In addition, our operations are exposed to potential natural disasters, including blizzards, tornadoes, storms, floods, other adverse weather conditions and earthquakes. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean‑up responsibilities, regulatory investigations and penalties or other damage resulting in curtailment or suspension of our operations. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues.
Our insurance may not be adequate to cover all losses or liabilities we may suffer. Furthermore, we may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In addition, sub‑limits have been imposed for certain risks. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we are not fully insured, it could have a material adverse effect on our business, results of operations and financial condition. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.
Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean‑up costs stemming from a sudden and accidental pollution event.

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However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. In addition, these policies do not provide coverage for all liabilities, and the insurance coverage may not be adequate to cover claims that may arise, or we may not be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti‑terrorist efforts and other armed conflicts involving the United States could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our services. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.
Increasing trucking regulations may increase our costs and negatively impact our results of operations.
In connection with our business operations, including the transportation and relocation of our hydraulic fracturing equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials (HAZMAT). Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the United States Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations.
We are subject to environmental laws and regulations, and future compliance, claims, and liabilities relating to such matters may have a material adverse effect on our results of operations, financial position or cash flows.
The nature of our operations, including the handling, transporting and disposing of a variety of fluids and substances, including hydraulic fracturing fluids and other regulated substances, air emissions, and wastewater discharges exposes us to some risks of environmental liability, including the release of pollutants from oil and natural gas wells and associated equipment to the environment. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be

20


imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Neighboring landowners and other third parties may file claims against us for personal injury or property damage allegedly caused by the release of pollutants into the environment. Environmental laws and regulations have changed in the past, and they may change in the future and become more stringent. Current and future claims and liabilities may have a material adverse effect on us because of potential adverse outcomes, defense costs, diversion of management resources, unavailability of insurance coverage and other factors. The ultimate costs of these liabilities are difficult to determine and may exceed any reserves we may have established. If existing environmental requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.
The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for oil and natural gas.
The EPA has determined that GHGs present an endangerment to public health and the environment because such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented, and continues to adopt and implement, regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). The EPA also requires the annual reporting of GHG emissions from certain large sources of GHG emissions in the United States, including certain oil and gas production facilities. The EPA has also taken steps to limit methane emissions from oil and gas production facilities. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one‑half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. And in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement entered into force in November 2016. On June 1, 2017, President Trump announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four‑year exit process beginning when it took effect in November 2016, which would resulting in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
Moreover, climate change may cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Beginning in August 2012, the EPA issued a series of rules under the CAA that establish new emission control requirements for emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment. After several attempts to delay implementation, in September 2018 the EPA issued a proposal to amend and reduce such requirements. In March 2015, the Bureau of Land Management (“BLM”) finalized a rule governing hydraulic fracturing on federal lands. In June 2016, a federal district court judge in Wyoming struck down the final rule, finding that the BLM lacked congressional authority to promulgate the rule. The BLM appealed that ruling. In September 2017, the U.S. Court of Appeals for the Tenth Circuit dismissed the appeal and remanded with

21


directions to vacate the lower court’s opinion, leaving the final rule in place. The BLM initiated a rulemaking to rescind the final rule in December 2017. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we or our customers operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.
More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells has caused increased seismic activity in certain areas. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico and Arkansas. The United States Geological Survey also noted the potential for induced seismicity in Ohio and Alabama. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, Oklahoma issued new rules for wastewater disposal wells in 2014 that imposed certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, has developed and implemented plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations. In particular, the Oklahoma Corporation Commission released well completion seismicity guidelines in December 2016 for operators in the SCOOP and STACK that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, in February 2017, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. The Texas Railroad Commission adopted similar rules in 2014. In addition, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters, and disposal or storage of fracturing wastewater in unlined pits. The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations.
Increased regulation of hydraulic fracturing and related activities (whether as a result of the EPA study results or resulting from other factors) could subject us and our customers to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, and plugging and abandonment requirements. New requirements could result in increased operational costs for us and our customers, and reduce the demand for our services.
Conservation measures, commercial development and technological advances could reduce demand for oil and natural gas and our services.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The commercial development of economically‑viable alternative energy sources and related products (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could have a similar effect. In addition, certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development, including the allowance of percentage depletion for oil and natural gas properties, may be eliminated as a result of proposed legislation. Any future decreases in the rate at which oil and natural gas reserves are

22


discovered or developed, whether due to the passage of legislation, increased governmental regulation leading to limitations, or prohibitions on exploration and drilling activity, including hydraulic fracturing, or other factors, could have a material adverse effect on our business and financial condition, even in a stronger oil and natural gas price environment.
We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition and results of operations.
We operate with most of our customers under master service agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer‑owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we depend on digital technologies to perform many of our services and process and record operational and accounting data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary information, personal information and other data, or other disruption of our business operations. In addition, certain cyber incidents, such as unauthorized surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks, including cyberattacks, may not be sufficient and may not protect against or cover all of the losses we may experience as a result of the realization of such risks. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate the effects of cyber incidents.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our shareholders, including:

23


limitations on the removal of directors;
limitations on the ability of our shareholders to call special meetings;
advance notice provisions for shareholder proposals and nominations for elections to the board of directors to be acted upon at meetings of shareholders;
providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and
establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by shareholders at shareholder meetings.
We may grow through acquisitions and our failure to properly plan and manage those acquisitions may adversely affect our performance.
We have completed and may in the future pursue, asset acquisitions or acquisitions of businesses. Any acquisition of assets or businesses involves potential risks, including the failure to realize expected profitability, growth or accretion; environmental or regulatory compliance matters or liability; title or permit issues; the incurrence of significant charges, such as impairment of goodwill, or property, plant and equipment or restructuring charges; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate. The process of upgrading acquired assets to our specifications and integrating acquired assets or businesses may also involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a significant amount time and resources and may divert management’s attention from existing operations or other priorities.
We must plan and manage any acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. Any failure to manage acquisitions effectively or integrate acquired assets or businesses into our existing operations successfully, or to realize the expected benefits from an acquisition or minimize any unforeseen operational difficulties, could have a material adverse effect on our business, financial condition, prospects or results of operations.
Our ability to use our net operating loss carryforwards may be limited.
As of December 31, 2018, we had approximately $516.0 million of federal net operating loss carryforwards that will begin to expire in 2032 and state net operating losses of approximately $50.0 million that will begin to expire in 2024. Utilization of these net operating loss carryforwards (“NOLs”) depends on many factors, including our future income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of taxable income that may be offset by NOLs when a corporation has undergone an “ownership change” (as determined under Section 382). Generally, a change of more than 50% in the ownership of a corporation’s stock, by value, over a three‑year period constitutes an ownership change for U.S. federal income tax purposes. Any unused annual limitation may, subject to certain limitations, be carried over to later years. We have experienced ownership changes, which may result in annual limitation under Section 382 determined by multiplying the value of our stock at the time of the ownership change by the applicable long‑term tax‑exempt rate as defined in Section 382, increased under certain circumstances as a result of recognizing built‑in gains in our assets existing at the time of the ownership change. The limitations arising from ownership changes may prevent utilization of our NOLs prior to their expiration. Future ownership changes or regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows if we attain profitability.
Future regulations relating to and interpretations of the recently enacted Tax Cuts and Jobs Act may have a material impact on our financial condition and results of operations.
The Tax Cuts and Jobs Act of 2017, or the Tax Act, was signed into law on December 22, 2017. Among other things, the Tax Act reduces the U.S. corporate tax rate from 35% to 21%, imposes significant additional limitations

24


on the deductibility of interest, and allows the expensing of capital expenditures. The Tax Act is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Act. The Treasury Department and the Internal Revenue Service continue to release regulations relating to and interpretive guidance of the legislation contained in the Tax Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our shareholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
We are subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report material weaknesses in internal control over financial reporting, our investors may lose confidence in our reported information and our stock price may be negatively affected.
We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002, or Section 404. Section 404 requires that we document and test our internal control over financial reporting and issue our management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm issue an attestation report on such internal control. If we fail to comply with the requirements of Section 404, or if we or our auditors identify and report material weaknesses in our internal control over financial reporting, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows.


25


Item 1B. Unresolved Staff Comments.
None.
Item 2.     Properties
Our corporate headquarters are located at 1706 S. Midkiff, Bldg. B, Midland, Texas 79701. In addition to our headquarters, we also own and lease other properties that are used for field offices, yards or storage in the Permian Basin. We believe that our facilities are adequate for our current operations.
Item 3.     Legal Proceedings.
From time to time we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We are not currently a party to any legal proceedings that we believe would have a material adverse effect on our financial position, results of operations or cash flows and are not aware of any material legal proceedings contemplated by governmental authorities.
Item 4.     Mine and Safety Disclosures
None.
Part II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information
On March 22, 2017, we consummated our initial public offering, or IPO, of our common stock at a price of $14.00 per share. Our common stock is traded on the New York Stock Exchange under the symbol “PUMP.” Prior to our IPO, there was no public market for our stock. We have set forth in the table below the quarterly information with respect to the high and low prices for each quarter in 2018 and 2017.
 
Price Per Share
of Common Stock
 
Dividends
Per Share
 
High
 
Low
 
2018
 
 
 
 
 
Fourth quarter
$
19.61

 
$
11.68

 
N/A
Third quarter
$
17.33

 
$
14.54

 
N/A
Second quarter
$
20.49

 
$
14.20

 
N/A
First quarter
$
22.49

 
$
15.25

 
N/A
 
Price Per Share
of Common Stock
 
Dividends
Per Share
 
High
 
Low
 
2017
 
 
 
 
 
Fourth quarter
$
20.49

 
$
13.81

 
N/A
Third quarter
$
14.48

 
$
10.92

 
N/A
Second quarter
$
14.70

 
$
11.93

 
N/A
First quarter
$
14.50

 
$
12.47

 
N/A

26


Holders
As of December 31, 2018, there were 100,190,126 shares of common stock outstanding, held of record by 4 holders. The number of record holders of our common stock does not include DTC participants or beneficial owners holding shares through nominee names.
Dividend
We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then‑existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, our ABL Credit Facility places restrictions on our ability to pay cash dividends.
Equity Compensation Plan Information
The following table sets forth our issuance of awards under our 2013 Stock Option Plan and 2017 Incentive Award Plan as of December 31, 2018:
Plan Category
 
Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)
 
Weighted average exercise price of outstanding options, warrants and rights
 
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
 
 
(a)
 
(b)
 
(c)
Equity compensation plans approved by security holders
 
5,727,911

 
5.14

 
3,874,852

Equity compensation plans not approved by security holders
 
N/A

 
N/A

 
N/A

Total
 
5,727,911

 
5.14

 
3,874,852

___________________
(1)    Includes 3,802,763 option awards under the 2013 Stock Option Plan, and 754,423 option awards, 473,505 restricted share unit awards and 697,220 performance stock unit awards (assuming achievement of maximum payout) that have been granted under the 2017 Incentive Award Plan. The weighted average exercise price in column (b) does not take the restricted share unit awards or performance stock unit awards into account.
Performance Graph
The quarterly changes for the periods shown in the following graph are based on the assumption that $100 had been invested in our common stock, the Russell 2000 Index (“Russell 2000”) and a self-constructed peer group Index of comparable companies (“Peer Group”) on March 17, 2017 (the first trading date of our common stock), and that all dividends were reinvested at the closing prices of the dividend payment dates. The relevant companies included in our Peer Group consists of Keane Group, Inc., RPC, Inc., C&J Energy Services, Inc., Basic Energy Services, Inc., Calfrac Well Services Ltd., Patterson-UTI Energy, Inc., Superior Energy Services, Inc and Mammoth Energy services. We included Mammoth Energy Services to our peer group in 2018 because we believe they are a relevant peer in assessing our performance. Subsequent measurement points are the last trading days of each quarter in 2017. We did not provide a five-year graph because we became a publicly traded company in March of 2017. The total cumulative dollar returns shown on the graph represent the value that such investments would have had on the

27


last trading date of 2018. The calculations exclude trading commissions and taxes. The stock price performance on the following graph and table is not necessarily indicative of future stock price performance.

chart-76b1ba05158957b5984.jpg
Date
 
Peer Group

 
Russell 2000

 
ProPetro Holding Corp.

3/17/2017
 
$
100.0

 
$
100.0

 
$
100.0

3/31/2017
 
$
97.3

 
$
99.6

 
$
88.9

6/30/2017
 
$
90.4

 
$
101.7

 
$
96.3

9/29/2017
 
$
97.3

 
$
107.1

 
$
99.0

12/29/2017
 
$
104.2

 
$
110.4

 
$
139.0

3/29/2018
 
$
83.4

 
$
109.9

 
$
109.6

6/29/2018
 
$
78.6

 
$
118.1

 
$
108.1

9/28/2018
 
$
74.8

 
$
121.9

 
$
113.7

12/31/2018
 
$
43.9

 
$
96.9

 
$
85.0


28


Item 6.     Selected Historical Financial Data.
The following table presents the available selected historical financial data of ProPetro Holding Corp. for the years indicated. There were no factors that materially affect the comparability of the information in the selected historical financial data presented.
The selected historical consolidated financial and operating data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes and other financial data included elsewhere in this annual report.

29



 
Year Ended December 31,
(In thousands, except for per share data)
2018
 
2017
 
2016
 
2015
Statement of Operations Data:
 
 
 
 
 
 
 
Revenue
$
1,704,562

 
$
981,865

 
$
436,920

 
$
569,618

Pressure pumping
1,658,403

 
945,040

 
409,014

 
510,198

All other
46,159

 
36,825

 
27,906

 
59,420

Costs and Expenses:
 
 
 
 
 
 
 
Cost of services(1)
1,270,577

 
813,823

 
404,140

 
483,338

General and administrative(2)
53,958

 
49,215

 
26,613

 
27,370

Depreciation and amortization
88,138

 
55,628

 
43,542

 
50,134

Property and equipment impairment expense

 

 
6,305

 
36,609

Goodwill impairment expense

 

 
1,177

 

Loss on disposal of assets
59,220

 
39,086

 
22,529

 
21,268

Total costs and expenses
1,471,893

 
957,752

 
504,306

 
618,719

Operating Income (Loss)
232,669

 
24,113

 
(67,386
)
 
(49,101
)
Other Income (Expense):
 
 
 
 
 
 
 
Interest expense
(6,889
)
 
(7,347
)
 
(20,387
)
 
(21,641
)
Gain on extinguishment of debt

 

 
6,975

 

Other expense
(663
)
 
(1,025
)
 
(321
)
 
(499
)
Total other expense
(7,552
)
 
(8,372
)
 
(13,733
)
 
(22,140
)
Income (loss) before income taxes
225,117

 
15,741

 
(81,119
)
 
(71,241
)
Income tax (expense) benefit
(51,255
)
 
(3,128
)
 
27,972

 
25,388

Net income (loss)
$
173,862

 
$
12,613

 
$
(53,147
)
 
$
(45,853
)
Per Share Information
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
Basic
$
2.08

 
$
0.17

 
$
(1.19
)
 
$
(1.31
)
Diluted
$
2.00

 
$
0.16

 
$
(1.19
)
 
$
(1.31
)
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
83,460

 
76,371

 
44,787

 
34,993
Diluted
87,046

 
79,583

 
44,787

 
34,993
Balance Sheet Data as of:
 
 
 
 
 
 
 
Cash and cash equivalents
$
132,700

 
$
23,949

 
$
133,596

 
$
34,310

Property and equipment — net of accumulated depreciation
$
912,846

 
$
470,910

 
$
263,862

 
$
291,838

Total assets
$
1,274,522

 
$
719,032

 
$
541,422

 
$
446,454

Long-term debt — net of deferred loan costs
$
70,000

 
$
57,178

 
$
159,407

 
$
236,876

Total shareholders’ equity
$
797,355

 
$
413,252

 
$
221,009

 
$
69,571

Cash Flow Statement Data:
 
 
 
 
 
 
 
Net cash provided by operating activities
$
393,079

 
$
109,257

 
$
10,659

 
$
81,230

Net cash used in investing activities
$
(280,604
)
 
$
(281,469
)
 
$
(41,688
)
 
$
(62,776
)
Net cash provided by (used in) financing activities
$
(3,724
)
 
$
62,565

 
$
130,315

 
$
(15,216
)
                                        
(1)
Exclusive of depreciation and amortization.
(2)
Inclusive of stock‑based compensation.



30


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
You should read the following discussion and analysis of our financial condition and results of operations together with our audited consolidated financial statements and the related notes included in this Form 10-K. Some of the information contained in this discussion and analysis or set forth elsewhere in this Form 10-K, including information with respect to our plans and strategy for our business and related financing, includes forward‑looking statements that involve risks and uncertainties. You should read the “Risk Factors” section of this Form 10-K for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward‑looking statements contained in the following discussion and analysis.
Basis of Presentation
Unless otherwise indicated, references in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” to “ProPetro Holding Corp.,” “the Company,” “we,” “our,” “us” or like terms refer to ProPetro Holding Corp. and its subsidiary.
Overview
Our Business
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, or 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. Further, our fleet has been designed to handle the highest intensity and most complex fracturing jobs. During the ended December 31, 2018, we continued our organic growth by purchasing and deploying four newbuild hydraulic fracturing units, bringing our hydraulic horsepower, or HHP capacity to 905,000 HHP, or 20 fleets. The Permian Basin is widely regarded as the most prolific oil‑producing area in the United States, and following our acquisition of pressure pumping and related assets from Pioneer and Pioneer Pumping Services, we believe we are currently the largest provider of hydraulic fracturing services in the region by HHP, with total horse power of 1,415,000 HHP, or 28 fleets.
Acquisition of Pioneer Pressure Pumping Assets
On December 31, 2018, we consummated the purchase of certain pressure pumping assets and real property from Pioneer and Pioneer Pumping Services. Prior to the purchase, the pressure pumping assets exclusively provided integrated pressure pumping services to Pioneer’s completion and production operations. The acquisition cost of the assets was comprised of $110.0 million of cash and 16.6 million shares of our common stock. In connection with the consummation of the transaction, we became a strategic long-term service provider to Pioneer, providing pressure pumping and related services for a term of up to 10 years.
The pressure pumping assets acquired include eight hydraulic fracturing fleets with a total of 510,000 HHP, four coiled tubing units and an associated equipment maintenance facility. Through this acquisition we expanded our existing presence in the Permian Basin, and increased our pumping capacity by 56%, to 28 hydraulic fracturing fleets with a total of 1,415,000 HHP, further strengthening our position as the largest pure-play provider of integrated well completion services in the Permian Basin.






31


2018 Operational Highlights
Over the course of the year ended December 31, 2018, we:
Purchased and put into service four newbuild hydraulic fracturing fleets;
Consummated the acquisition of pressure pumping and related assets from Pioneer and Pioneer Pumping Services, adding eight hydraulic fracturing fleets, or 510,000 HHP, and ancillary equipment, expanding our total horse power to 1,415,000 HHP or 28 hydraulic fracturing fleets after giving effect to the acquisition;
In connection with the asset acquisition, entered into a long-term strategic relationship with Pioneer, an industry leading E&P company, to provide pressure pumping and related services for a term of up to 10 years;
Increased our ABL Credit Facility from $200.0 million to $300.0 million, while extending the term of the facility; and
Maintained a conservative balance sheet and sufficient liquidity.
Regional sand pumped increased significantly in 2018 from 14.7% in January 2018 to 71.6% in December 2018, which slightly impacted sand revenue offset by increased margin percentage.
2018 Financial Highlights
Among other financial highlights, for the year ended December 31, 2018:
Revenue increased $722.7 million, or 73.6%, to $1,704.6 million, as compared to $981.9 million for the year ended December 31, 2017, primarily as a result of the increase in our fleet size;
Cost of services (exclusive of depreciation and amortization) increased $456.8 million or 56.1% to $1,270.6 million, as compared to $813.8 million for the year ended December 31, 2017, primarily as a result of the increase in fleet size, resulting in higher activity levels. Cost of services as a percentage of revenue decreased to 74.5% in 2018 compared to 82.9% for the year ended December 31, 2017;
General and administrative expenses, inclusive of stock-based compensation (“G&A”), increased $4.7 million, or 9.6% to $54.0 million, as compared to $49.2 million for the December 31, 2017. G&A as a percentage of revenue decreased to 3.2% in 2018 from 5.0% for the year ended December 31, 2017;
Diluted net income per common share was $2.00, compared to $0.16 for the year ended December 31, 2017.
2019 Outlook
In 2019, we continue to focus on providing best-in-class service to our customers, helping our customer improve their well economics while continuing to enhance the Company’s profitability. We expect to achieve these objectives through:
continuing to enhance our dedicated customer model to drive production efficiencies;
maintaining full utilization of our hydraulic fracturing fleets;
pursuing operational efficiencies and cost reduction strategies;
pursuing expansion opportunities for our non-hydraulic fracturing operations;
maintaining our existing relationships with our vendors and developing strategic relationships with new suppliers to ensure continuity;
exploring potential opportunities for mergers or acquisitions, focused on our growth, market opportunities and creating value to our shareholders.

32


Our Assets and Operations
Through our pressure pumping segment, which includes cementing operations, we primarily provide hydraulic fracturing services (inclusive of acidizing 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. We have fully maintained our equipment throughout the recent industry downturn to ensure optimal performance and reliability.
In addition to our core pressure pumping segment operations, we also offer a suite of complementary well completion and production services, including coiled tubing and flowback services. 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.
How We Generate Revenue
We generate revenue primarily through our pressure pumping segment, and more specifically, by providing hydraulic fracturing services to our customers. We own and operate a fleet of mobile hydraulic fracturing units and other auxiliary equipment to perform fracturing services. We also provide personnel and services that are tailored to meet each of our customers’ needs. We charge our customers on a per‑job basis, in which we set pricing terms after receiving full specifications for the requested job, including the lateral length of the customer’s wellbore, the number of frac stages per well, the amount of proppant to be employed and other parameters of the job.
In addition to hydraulic fracturing services, we generate revenue through the complementary services that we provide to our customers, including cementing, coiled tubing and flowback services. These complementary services are provided through various contractual arrangements, including on a turnkey contract basis, in which we set a price to perform a particular job, or a daywork contract basis, in which we are paid a set price per day for our services. We are also sometimes paid by the hour for these complementary services.
Our revenue, profitability and cash flows are highly dependent upon prevailing crude oil prices and expectations about future prices. For many years, oil prices and markets have been extremely volatile. Prices are affected by many factors beyond our control. West Texas Intermediate (“WTI”) oil prices which declined significantly in 2015 and 2016, but recovered somewhat during 2017 and 2018. The average WTI oil prices per barrel was $65.1, $50.8 and $43.3 for the years ended December 31, 2018, 2017 and 2016, respectively. 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, if oil prices increase, we believe U.S. rig counts will also increase, which may result in an increase in demand for drilling and pressure pumping services. 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, as well as rig count.
The historical average Permian Basin rig counts based on the weekly Baker Hughes Incorporated rig count information were as follows:
 
Year Ended December 31
Drilling Type (Permian Basin)
2018
 
2017
 
2016
Directional
6

 
6

 
2

Horizontal
418

 
311

 
154

Vertical
43

 
39

 
26

Total
467

 
356

 
182


33



Costs of Conducting our Business
The principal direct costs involved in operating our business are expendables, other direct costs, and direct labor costs. Generally, we price each job to reflect a predetermined margin over our expendables and direct labor costs. Our fixed costs are relatively low and a large portion of the costs described below are only incurred as we perform jobs for our customers.
Expendables. Expendables are the largest expenses incurred, and include the product and freight costs associated with proppant, chemicals and other consumables used in our pressure pumping and other operations. These costs comprise a substantial variable component of our service costs, particularly with respect to the quantity and quality of sand and chemicals demanded when providing hydraulic fracturing services. Expendable product costs comprised approximately 56.0%, 61.3% and 61.0% of total costs of service for the years ended December 31, 2018, 2017 and 2016, respectively. The decrease in our expendable product cost as a percentage of revenue in 2018 is primarily attributable to the increase in the number of customers self-sourcing these expendables and an increase in the use of less expensive regional sand.
Other Direct Costs. We incur other direct expenses related to our service offerings, including the costs of fuel, repairs and maintenance, general supplies, equipment rental and other miscellaneous operating expenses. Fuel is consumed both in the operation and movement of our hydraulic fracturing fleet and other equipment. Repairs and maintenance costs are expenses directly related to upkeep of equipment, which have been amplified by the demand for higher horsepower jobs. Capital expenditures to upgrade or extend the useful life of equipment are not included in other direct costs. Other direct costs were 30.9%, 26.5% and 24.4% of total costs of service for the years ended December 31, 2018, 2017 and 2016, respectively.
Direct Labor Costs. Payroll and benefit expenses related to our crews and other employees that are directly attributable to the effective delivery of services are included in our operating costs. Direct labor costs amounted to 13.1%, 12.2% and 14.5% of total costs of service for the years ended December 31, 2018, 2017 and 2016, respectively.
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 or Adjusted EBITDA margin.
Adjusted EBITDA and Adjusted EBITDA margin
We view Adjusted EBITDA or 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) (gain) on extinguishment of debt, (iii) stock based compensation, and (iv) other unusual or non‑recurring (income)/expenses, such as impairment and costs related to our initial public offering. Adjusted EBITDA margin reflects our Adjusted EBITDA as a percentage of our revenues.
Adjusted EBITDA or 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 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 generally accepted accounting principles in the United States of America (“GAAP”).

34



Note Regarding Non‑GAAP Financial Measures
Adjusted EBITDA and Adjusted EBITDA margin are usually 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 or 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 or 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 or Adjusted EBITDA margin may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Reconciliation of net income (loss) to Adjusted EBITDA:
($ in thousands)
Pressure
Pumping
 
All Other
 
Total
Year ended December 31, 2018
 
 
 
 
 
Net income (loss)
$
253,196

 
$
(79,334
)
 
$
173,862

Depreciation and amortization
83,404

 
4,734

 
88,138

Interest expense

 
6,889

 
6,889

Income tax expense

 
51,255

 
51,255

Loss (gain) on disposal of assets
59,962

 
(742
)
 
59,220

Stock‑based compensation

 
5,482

 
5,482

Other expense

 
663

 
663

Other general and administrative expense (1)
2

 
203

 
205

Deferred IPO Bonus
1,832

 
977

 
2,809

Adjusted EBITDA
$
398,396

 
$
(9,873
)
 
$
388,523



35


($ in thousands)
Pressure
Pumping
 
All Other
 
Total
Year ended December 31, 2017
 
 
 
 
 
Net income (loss)
$
50,417

 
$
(37,804
)
 
$
12,613

Depreciation and amortization
51,155

 
4,473

 
55,628

Interest expense

 
7,347

 
7,347

Income tax expense

 
3,128

 
3,128

Loss on disposal of assets
38,059

 
1,027

 
39,086

Stock‑based compensation

 
9,489

 
9,489

Other expense

 
1,025

 
1,025

Other general and administrative expense (1)

 
722

 
722

Deferred IPO Bonus
5,491

 
2,914

 
8,405

Adjusted EBITDA
$
145,122

 
$
(7,679
)
 
$
137,443

 
 
 
 
 
 
 
Pressure
Pumping
 
All Other
 
Total
Year ended December 31, 2016
 
 
 
 
 
Net loss
$
(45,316
)
 
$
(7,831
)
 
$
(53,147
)
Depreciation and amortization
37,282

 
6,260

 
43,542

Interest expense

 
20,387

 
20,387

Income tax benefit

 
(27,972
)
 
(27,972
)
Loss on disposal of assets
23,690

 
(1,161
)
 
22,529

Property and equipment impairment expense

 
6,305

 
6,305

Goodwill impairment expense

 
1,177

 
1,177

Gain on extinguishment of debt

 
(6,975
)
 
(6,975
)
Stock‑based compensation

 
1,649

 
1,649

Other expense

 
321

 
321

Adjusted EBITDA
$
15,656

 
$
(7,840
)
 
$
7,816

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


36


Results of Operations
We conduct our business through five operating segments: hydraulic fracturing, cementing, coil tubing, flowback and drilling. For reporting purposes, the hydraulic fracturing (which now includes our acidizing operations) and cementing operating segments are aggregated into our one reportable segment, pressure pumping. On August 31, 2018, we divested our surface air drilling segment in order to continue to position ourselves as a Permian Basin-focused pressure pumping business because we believe the pressure pumping market in the Permian Basin offers more supportive long-term growth fundamentals. In addition, with increased focus on our pressure pumping operations, 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. Accordingly, we anticipate the financial significance of our drilling segment relative to the financial results from pressure pumping and other service offerings to continue to decline.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
($ in thousands, except percentages)
 
YEAR ENDED
 
CHANGE
 
 
2018
 
2017
 
Variance
 
%
Revenue
 
$
1,704,562

 
$
981,865

 
$
722,697

 
73.6
 %
Cost of services (1)
 
1,270,577

 
813,823

 
456,754

 
56.1
 %
General and administrative expense (2)
 
53,958

 
49,215

 
4,743

 
9.6
 %
Depreciation and amortization
 
88,138

 
55,628

 
32,510

 
58.4
 %
Loss on disposal of assets
 
59,220

 
39,086

 
20,134

 
51.5
 %
Interest expense
 
6,889

 
7,347

 
(458
)
 
(6.2
)%
Other expense
 
663

 
1,025

 
(362
)
 
(35.3
)%
Income tax expense
 
51,255

 
3,128

 
48,127

 
1,538.6
 %
 
 
 
 
 
 
 
 
 
Net income
 
$
173,862

 
$
12,613

 
$
161,249

 
1,278.4
 %
 

 

 
 
 
 
Adjusted EBITDA (3)
 
$
388,523

 
$
137,443

 
$
251,080


182.7
 %
Adjusted EBITDA Margin (3)
 
22.8
%
 
14.0
%
 
8.8
%
 
62.9
 %
 
 
 

 
 

 
 
 
 
Pressure pumping segment results of operations:
 
 
 
 
 
 
 
 
Revenue
 
$
1,658,403

 
$
945,040

 
$
713,364

 
75.5
 %
Cost of services
 
$
1,236,262

 
$
784,349

 
$
451,912

 
57.6
 %
Adjusted EBITDA
 
$
398,396

 
$
145,122

 
$
253,274

 
174.5
 %
Adjusted EBITDA Margin (4)
 
24.0
%
 
15.4
%
 
8.6
%
 
55.8
 %
____________________
(1)
Exclusive of depreciation and amortization.
(2)
Inclusive of stock‑based compensation.
(3)
For definitions of the non‑GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA margin and reconciliation of Adjusted EBITDA and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read “How We Evaluate Our Operations”.
(4)
The 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 revenues for the pressure pumping segment.

37



Revenue.  Revenue increased 73.6%, or $722.7 million, to $1,704.6 million for the year ended December 31, 2018, as compared to $981.9 million for the year ended December 31, 2017. The increase was primarily attributable to the increase in activity levels resulting from increase in fleet size and demand for our services. Our pressure pumping segment revenues increased 75.5%, or $713.4 million for the year ended December 31, 2018, as compared to the year ended December 31, 2017. Revenues from services other than pressure pumping increased 25.3%, or $9.3 million, for the year ended December 31, 2018, as compared to the year ended December 31, 2017. The increase in revenues from services other than pressure pumping during the year ended December 31, 2018, was primarily attributable to the increase in demand for our flowback and coil tubing services.
Cost of Services.  Cost of services increased 56.1%, or $456.8 million, to $1,270.6 million for the year ended December 31, 2018, from $813.8 million during the year ended December 31, 2017. Cost of services in our pressure pumping segment increased $451.9 million during the year ended December 31, 2018, as compared to the year ended December 31, 2017. 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 74.5% for the year ended December 31, 2018, as compared to 83.0% for the year ended December 31, 2017. The decrease in cost of services as a percentage of revenue in our pressure pumping segment is attributed to the increased revenue from operational efficiencies and our cost control initiatives, which resulted in significantly higher realized Adjusted EBITDA margins during the year ended December 31, 2018.
General and Administrative Expenses.  General and administrative expenses increased 9.6%, or $4.7 million, to $54.0 million for the year ended December 31, 2018, as compared to $49.2 million for the year ended December 31, 2017. The net increase was primarily attributable to increases in payroll, insurance, property taxes, legal and professional fees, traveling expenses, subscriptions and dues and other general and administrative expenses totaling $14.3 million, and offset by a decrease in stock compensation expense of $4.0 million and deferred IPO cash bonus of $5.6 million.
Depreciation and Amortization.  Depreciation and amortization increased 58.4%, or $32.5 million, to $88.1 million for the year ended December 31, 2018, as compared to $55.6 million for the year ended December 31, 2017. The increase was primarily attributable to additional property and equipment purchased and put into service in the year ended December 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 increased 51.5%, or $20.1 million, to $59.2 million for the year ended December 31, 2018, as compared to $39.1 million for the year ended December 31, 2017. The increase was primarily attributable to increase in our fleet size and greater intensity of jobs completed.
Interest Expense.  Interest expense decreased 6.2%, or $0.5 million, to $6.9 million for the year ended December 31, 2018, as compared to $7.3 million for the year ended December 31, 2017. The decrease in interest expense was primarily attributable to a reduction of our average debt balance in 2018 compared to 2017.
Other Expense.  Other expense was $0.7 million for the year ended December 31, 2018, as compared to $1.0 million for the year ended December 31, 2017. The decrease was primarily attributable to a decrease in lenders related expenses, non-recurring listing related expenses, and the loss associated with the change in the fair value of our extinguished interest rate swap liability.
Income Tax Expense.  Income tax expense was $51.3 million for the year ended December 31, 2018, as compared to $3.1 million for the year ended December 31, 2017. The increase in our provision for income tax expense is primarily attributable to the increase in book income in 2018 compared to 2017. Additionally, the income tax expense during the year ended December 31, 2017, included a one-time deferred tax benefit offset of $3.4 million, resulting from the U.S. government enacted tax legislation commonly referred to as the Tax Cuts and Jobs Act (“Tax Act”). 

38


Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
 
 
YEAR ENDED
 
CHANGE
($ in thousands, except percentages)
 
2017
 
2016
 
Variance
 
%
Revenue
 
$
981,865

 
$
436,920

 
$
544,945

 
124.7
 %
Cost of services (1)
 
813,823

 
404,140

 
409,683

 
101.4
 %
General and administrative expense (2)
 
49,215

 
26,613

 
22,602

 
84.9
 %
Depreciation and amortization
 
55,628

 
43,542

 
12,086

 
27.8
 %
Property and equipment impairment
 

 
6,305

 
(6,305
)
 
(100.0
)%
Goodwill impairment
 

 
1,177

 
(1,177
)
 
(100.0
)%
Loss on disposal of assets
 
39,086

 
22,529

 
16,557

 
73.5
 %
Interest expense
 
7,347

 
20,387

 
(13,040
)
 
(64.0
)%
Gain on extinguishment of debt
 

 
(6,975
)
 
(6,975
)
 
(100.0
)%
Other expense
 
1,025

 
321

 
704

 
219.3
 %
Income tax expense (benefit)
 
3,128

 
(27,972
)
 
(31,100
)
 
(111.2
)%
 
 
 
 
 
 
 
 
 
Net income (loss)
 
$
12,613

 
$
(53,147
)
 
$
65,760

 
123.7
 %
 
 
 
 
 
 
 
 
 
Adjusted EBITDA (3)
 
$
137,443

 
$
7,816

 
$
129,627

 
1,658.5
 %
Adjusted EBITDA Margin (3)
 
14.0
%
 
1.8
%
 
12.2
%
 
677.8
 %
 
 
 

 
 

 
 
 
 
Pressure pumping segment results of operations:
 
 
 
 
 
 
 
 
Revenue
 
$
945,040

 
$
409,014

 
$
536,025

 
131.1
 %
Cost of services
 
$
784,349

 
$
379,815

 
$
404,534

 
106.5
 %
Adjusted EBITDA
 
$
145,122

 
$
15,656

 
$
129,466

 
826.9
 %
Adjusted EBITDA Margin (4)
 
15.4
%
 
3.8
%
 
11.6
%
 
305.3
 %
____________________
(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 and Adjusted EBITDA margin to our most directly comparable financial measures calculated in accordance with GAAP, please read ““How We Evaluate Our Operations”.
(4)
The 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 revenues for the pressure pumping segment.

Revenue.  Revenue increased 124.7%, or $544.9 million, to $981.9 million for the year ended December 31, 2017, as compared to $436.9 million for the year ended December 31, 2016. The increase was primarily attributable to the increase in customer activity, fleet size and demand for our services, which led to an increase in pricing for our hydraulic fracturing and other services. Our pressure pumping segment revenues increased 131.1%, or $536.0 million for the year ended December 31, 2017, as compared to the year ended December 31, 2016. Revenues from services other than pressure pumping increased 32.0%, or $8.9 million, for the year ended December 31, 2017, as compared to the year ended December 31, 2016. The increase in revenues from services other than pressure pumping during the year ended December 31, 2017 was primarily attributable to the increase in revenues and customer demand for our flowback, coil tubing and surface drilling services, offset by the decrease in revenue from idling of our drilling rigs.

39


Cost of Services.  Cost of services increased 101.4%, or $409.7 million, to $813.8 million for the year ended December 31, 2017, from $404.1 million during the year ended December 31, 2016. Cost of services in our pressure pumping segment increased $404.5 million during the year ended December 31, 2017, as compared to the year ended December 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 83.0% for the year ended December 31, 2017, as compared to 92.9% for the year ended December 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 certain costs, which resulted in significantly higher realized Adjusted EBITDA margins during the year ended December 31, 2017.
General and Administrative Expenses.  General and administrative expenses increased 84.9%, or $22.6 million, to $49.2 million for the year ended December 31, 2017, as compared to $26.6 million for the year ended December 31, 2016. The net increase was primarily attributable to increases in payroll, insurance, advertising, communication, office expense, travel and legal costs, totaling $8.3 million, and an IPO bonus of $8.4 million to key employees, along with $7.8 million increase in stock compensation recorded during the year ended December 31, 2017, and offset by a decrease in property taxes of $1.6 million, and other remaining general and administrative expenses of $0.3 million. General and administrative expenses as a percentage of total revenues decreased to 5.0% for the year ended December 31, 2017, as compared to 6.1% for the year ended December 31, 2016, excluding non-recurring deferred IPO bonus of $8.4 million and stock compensation expense of $6.8 million, general and administrative expenses as a percentage of total revenues decreased to 3.5% for the year ended December 31, 2017, as compared to 6.1% for the year ended December 31, 2016. The decrease in general and administrative expenses as a percentage of total revenue is as a result of the higher revenue during the year ended December 31, 2017.
Depreciation and Amortization.  Depreciation and amortization increased 27.8%, or $12.1 million, to $55.6 million for the year ended December 31, 2017, as compared to $43.5 million for the year ended December 31, 2016. The increase was primarily attributable to additional property and equipment purchased and put into service in the year ended December 31, 2017. We calculate depreciation of property and equipment using the straight-line method.
Property and Equipment Impairment Expense. There was no property and equipment impairment expense during the year ended December 31, 2017, compared to $6.3 million during the year ended December 31, 2016. The non‑cash impairment expense in 2016 was associated with our drilling rigs, and was recognized as a result of depressed commodity prices and a negative future near‑term outlook for these assets.
Goodwill Impairment Expense. There was no goodwill impairment expense during the year ended December 31, 2017, compared to $1.2 million during the year ended December 31, 2016. The non‑cash goodwill impairment expense in 2016 was as a result of the write‑down of goodwill related to our surface drilling reporting unit.
Loss on Disposal of Assets.  Loss on the disposal of assets increased 73.5%, or $16.6 million, to $39.1 million for the year ended December 31, 2017, as compared to $22.5 million for the year ended December 31, 2016. The increase was primarily attributable to greater service intensity of jobs completed, coupled with higher fleet size, activity levels and utilization of our equipment.
Interest Expense.  Interest expense decreased 64.0%, or $13.0 million, to $7.3 million for the year ended December 31, 2017, as compared to $20.4 million for the year ended December 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 in the first quarter of 2017.
Gain on Extinguishment of Debt.  There was no debt extinguishment gain or loss during the year ended December 31, 2017, compared to the gain on extinguishment of debt, net of cost, of $7.0 million during the year ended December 31, 2016. The gain on extinguishment of debt during 2016 was as a result of the auction process with our lenders to repurchase $37.5 million of our term loan at a 20% discount to par value.

40


Other Expense.  Other expense was $1.0 million for the year ended December 31, 2017, as compared to $0.3 million for the year ended December 31, 2016. The increase was primarily attributable to an increase in lenders related expenses, non-recurring listing related expenses, and partially offset by an increase in the unrealized gain resulting from the change in the fair value of our interest rate swap liability at December 31, 2017 compared to December 31, 2016.
Income Tax Expense/(Benefit).  Income tax expense was $3.1 million for the year ended December 31, 2017, compared to income tax benefit of $28.0 million, for the year ended December 31, 2016. The change from an income tax benefit to income tax expense is primarily due to the Company’s reporting income before taxes during the year ended December 31, 2017, compared to a loss before taxes recorded during the year ended December 31, 2016. The income before taxes generated is attributable to the increase in our revenue during the year ended December 31, 2017, compared to December 31, 2016. Additionally, the income tax expense during the year ended December 31, 2017, included a one-time deferred tax benefit offset of $3.4 million, resulting from the U.S. government enacted tax legislation commonly referred to as the Tax Cuts and Jobs Act (“Tax Act”). 
Liquidity and Capital Resources
Our liquidity is currently provided by (i) existing cash balances, (ii) operating cash flows and (iii) borrowings under our ABL Credit Facility. Our primary uses of cash will be to continue to fund our operations, support growth opportunities and satisfy debt payments. As of December 31, 2018, our total liquidity consists of cash and cash equivalents of $132.7 million, and $125.0 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 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.
Cash and Cash Flows
The following table sets forth our net cash provided by (used in) operating, investing and financing activities during the year at December 31, 2018, 2017 and 2016, respectively.
 
Year Ended December 31,
($ in thousands)
2018
 
2017
 
2016
Net cash provided by operating activities
$
393,079

 
$
109,257

 
$
10,659

Net cash used in investing activities
$
(280,604
)
 
$
(281,469
)
 
$
(41,688
)
Net cash (used in) provided by financing activities
$
(3,724
)
 
$
62,565

 
$
130,315

Operating Activities
Net cash provided by operating activities was $393.1 million for the year ended December 31, 2018, as compared to $109.3 million for the year ended December 31, 2017. The net increase of $283.8 million was primarily due to the increase in our revenue generating assets (fleet size), which has resulted in increases in revenue and net income in the year, offset by our working capital needs resulting from higher fleet size and expanding activity levels.
Net cash provided by operating activities was $109.3 million for the year ended December 31, 2017, as compared to $10.7 million for the year ended December 31, 2016. The net increase of $98.6 million was primarily due to an increase in revenue and net income in the year, resulting from an increase in customer activity, fleet size and demand for our services, and partially offset by the increase in our working capital needs resulting from higher fleet size and expanding activity levels.

41


Investing Activities
Net cash used in investing activities decreased to $280.6 million for the year ended December 31, 2018, from $281.5 million for the year ended December 31, 2017. The slight decrease was primarily attributable to the decrease in cash payment for capital expenditures during the year ended December 31, 2018, compared to the year ended December 31, 2017.
Net cash used in investing activities increased to $281.5 million for the year ended December 31, 2017, from $41.7 million for the year ended December 31, 2016. The increase was primarily attributable to the additional hydraulic fracturing units and other ancillary equipment purchased and a marginal increase in maintenance capital expenditures, during the year ended December 31, 2017, compared to the year ended December 31, 2016.
Financing Activities
Net cash used in financing activities was $3.7 million for the year ended December 31, 2018, compared to net cash provided of $62.6 million for the year ended December 31, 2017. Our net cash used in financing activities during the year ended December 31, 2018 was primarily driven by cash used for repayment of borrowings of $80.9 million, repayment of insurance financing of $4.5 million, debt issuance cost of $1.7 million, which was partially offset by cash proceeds from insurance financing $5.8 million and borrowings of $77.4 million. Our net cash provided by financing activities during the year ended December 31, 2017 was primarily from borrowings of $60.0 million, insurance financing proceeds of $4.1 million and initial public offerings (IPO) proceeds of $185.5 million, partially offset by repayment of borrowings of $166.5 million, repayment of insurance financing of $3.8 million, debt issuance of $1.7 million and IPO costs of $15.1 million.
Net cash provided by financing activities was $62.6 million for the year ended December 31, 2017, compared to $130.3 million for the year ended December 31, 2016. The net decrease in cash provided from financing activities was primarily attributable to the repayment of borrowings $166.5 million, repayment of insurance financing of $3.8 million, debt issuance cost of $1.7 million, payment of IPO costs of $15.1 million and offset by the receipt of $185.5 million of IPO proceeds, insurance financing proceeds of $4.1 million and proceeds from borrowings of $60.0 million during the year ended December 31, 2017, compared to net cash used of $71.3 million for repayment of borrowings, repayment of insurance financing of $4.5 million, payment of preferred equity financing costs of $7.5 million, debt extinguishment, debt issuance and IPO costs of $1.0 million, offset by insurance financing proceeds of $4.1 million, equity capitalization proceeds of $40.4 million and proceeds from preferred equity capitalization of $170.0 million during the year ended December 31, 2016.
Credit Facility and Other Financing Arrangements
ABL Credit Facility
On March 22, 2017, we entered into a new revolving credit facility with a $150 million borrowing capacity, or the 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 term 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.

42


On February 22, 2018, we entered into a first amendment with our lenders to increase the capacity of the ABL Credit Facility. The amendment increased total capacity under the facility from $150.0 million to $200.0 million. The first amendment to ABL Credit Facility modified the 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 and the Borrowing Base and (ii) $15 million.
On December 19, 2018, we entered into a second amendment with our lenders to further increase the capacity of the ABL Credit Facility. The second amendment increased total capacity under the facility from $200.0 million to $300.0 million and extended the maturity date of the ABL Credit Facility from March 22, 2022 until December 19, 2023. The second amendment to the ABL Credit Facility further modified the 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 and the Borrowing Base and (ii) $22.5 million.
Equipment Financing Arrangements
On November 24, 2015, we entered into a 36‑month equipment financing arrangement for three hydraulic fracturing units, and received proceeds of $25.0 million. A portion of the proceeds were used to pay off manufacturer notes, and the remainder was used for additional liquidity. As of December 31, 2018, we have fully repaid all outstanding balance and met all obligations under this financing arrangement
On June 30, 2017, we entered into a financing arrangement for the purchase of light vehicles. As of December 31, 2018, we have fully repaid all outstanding balance and met all obligations under this financing arrangement.
Off Balance Sheet Arrangements
We had no off balance sheet arrangements as of December 31, 2018.
Capital Requirements
Capital expenditures incurred were $592.6 million during the year ended December 31, 2018, as compared to $305.3 million during the year ended December 31, 2017. The increase was primarily attributable to our acquisition of Pioneer’s pressure pumping assets, which includes eight hydraulic fracturing fleets, four coiled tubing units and an associated equipment maintenance building.
Capital expenditures incurred were $305.3 million during the year ended December 31, 2017 as compared to $46.0 million during the year ended December 31, 2016. The increase was primarily attributable to additional property and equipment purchased.
Contractual Obligations
The following table presents our contractual obligations and other commitments as of December 31, 2018.
($ in thousands)
 
 
Payment Due by Period
 
Total
 

1 year or less
 
2 - 3 years
 
4 - 5 years
 
More than
5 years
ABL Credit Facility (1)
$
70,000

 
$

 
$

 
$
70,000

 
$

Operating leases(2)   
5,313

 
892

 
1,442

 
2,979

 

Total contractual obligations
$
75,313

 
$
892

 
$
1,442

 
$
72,979

 
$

____________________
(1)
The ABL Credit Facility balance outstanding is exclusive of future commitment fees, interest or other fees since our potential future obligations thereunder are based on future events and cannot be reasonably estimated.
(2) Operating leases include agreements for various office and maintenance locations.


43


Recent Accounting Pronouncements
Disclosure concerning recently issued accounting standards is incorporated by reference to Note 2 of our Consolidated Financial Statements contained in this Form 10-K.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally acceptable in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported revenues and expenses during the years. We evaluate these estimates and assumptions on an ongoing basis and base our estimates on historical experience, current conditions and various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities as well as identifying and assessing the accounting treatment with respect to commitments and contingencies. Our actual results may materially differ from these estimates.
Listed below are the accounting policies that we believe are critical to our financial statements due to the degree of uncertainty regarding the estimates or assumptions involved, and that we believe are critical to the understanding of our operations.
Property and Equipment
Our property and equipment are recorded at cost, less accumulated depreciation.
Upon sale or retirement of property and equipment, the cost and related accumulated depreciation are removed from the balance sheet and the net amount, less proceeds from disposal, is recognized as a gain or loss in earnings.
We retired certain components of equipment rather than entire pieces of equipment, which resulted in a net loss on disposal of assets of $59.2 million, $39.1 million and $22.5 million for the years ended December 31, 2018, 2017 and 2016, respectively.
Depreciation of property and equipment is provided on the straight‑line method over estimated useful lives as shown in the table below. The estimated useful lives and salvage values of property and equipment is subject to key assumptions such as maintenance, utilization and job variation. Unanticipated future changes in these assumptions could negatively or positively impact our net income. A 10% change in the useful lives of our property and equipment would have resulted in approximately $8.8 million impact on pre-tax income during the year ended December 31, 2018.
Land
Indefinite
Buildings and property improvements
5 - 30 years
Vehicles
1 ‑ 5 years
Equipment
1 ‑ 20 years
Leasehold improvements
5 ‑ 20 years
Impairment of Long-Lived Assets
In accordance with the Financial Accounting Standards Board Accounting Standards Codification (ASC) 360 regarding Accounting for the Impairment or Disposal of Long‑Lived Assets, we review the long‑lived assets to be held and used whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future undiscounted cash flows attributable

44


to the assets is less than the carrying amount of such assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. Our cash flow forecasts require us to make certain judgements regarding long‑term forecasts of future revenue and costs and cash flows related to the assets subject to review. The significant assumption in our cash flow forecasts is our future growth expectations. The significant assumption is uncertain in that it is driven by future demand for our services and utilization which could be impacted by crude oil market prices, future market conditions and technological advancements. Our fair value estimates for certain long‑lived assets require us to use significant other observable inputs among others, including significant assumptions related to market approach based on recent auction sales or selling prices of comparable equipment. The estimates of fair value are also subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. No events or changes in circumstances occurred that would indicate an impairment of our property and equipment during the year ended December 31, 2018.
If the crude oil market declines or the demand for vertical drilling does not recover, and if the equipment remains idle or under‑utilized, the estimated fair value of such equipment may decline, which could result in future impairment charges. Though the impacts of variations in any of these factors can have compounding or off‑setting impacts, a 10% decline in the estimated fair value of our drilling assets at December 31, 2018 would result in additional impairment of $0.5 million, and a 10% decline in the estimated future cash flows for our other asset groups would not indicate an impairment.
Income Taxes
Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined on the basis of differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We recognize deferred tax assets to the extent that we believe these assets are more likely than not to be realized. In making such a determination, we consider all positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, and the results of recent operations. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes. In determining the reasonableness of our valuation allowance as of December 31, 2018, we have considered and made judgments and estimates regarding estimated future taxable income. These estimates and judgments include some degree of uncertainty and changes in these estimates and assumptions could require us to adjust the valuation allowances for our deferred tax assets and the ultimate realization of tax assets depends on the generation of sufficient taxable income.
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (“Tax Act”).  The Tax Act makes broad and complex changes to the U.S. tax code including, but not limited to (1) reducing the U.S. federal corporate tax rate from 35% to 21%, (2) eliminating the corporate alternative minimum tax (AMT) and changing how existing AMT credits can be realized, (3) creating a new limitation on deductible interest expense, (4) changes to bonus depreciation, and (5) changing rules related to use and limitations of net operating loss carryforwards for tax years beginning after December 31, 2017.  The only material items that impacted the Company’s consolidated financial statements in 2017 were bonus depreciation and the corporate rate reduction.  While the corporate rate reduction is effective January 1, 2018, we accounted for this anticipated rate change during the year ended December 31, 2017, the year of enactment.  Consequently, we recorded a $3.4 million decrease to the net deferred tax liability, with a corresponding net adjustment to deferred tax benefit in our consolidated financial statements for the year ended December 31, 2017.
Our methodology for recording income taxes requires a significant amount of judgment in the use of assumptions and estimates. Additionally, we forecast certain tax elements, such as future taxable income, as well as

45


evaluate the feasibility of implementing tax planning strategies. Given the inherent uncertainty involved with the use of such variables, there can be significant variation between anticipated and actual results. Unforeseen events may significantly impact these variables, and changes to these variables could have a material impact on our income tax accounts. The final determination of our income tax liabilities involves the interpretation of local tax laws and related authorities in each jurisdiction. Changes in the operating environments, including changes in tax law, could impact the determination of our income tax liabilities for a tax year.

46


Item 7A. Quantitative and Qualitative Disclosure of Market Risks
Market risk is the risk of loss arising from adverse changes in market rates and prices. Historically, our risks have been predominantly related to potential changes in the fair value of our long‑term debt due to fluctuations in applicable market interest rates. Going forward our market risk exposure generally will be limited to those risks that arise in the normal course of business, as we do not engage in speculative, non‑operating transactions, nor do we utilize financial instruments or derivative instruments for trading purposes.
Commodity Price Risk
Our material and fuel purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our pressure pumping services such as proppants, chemicals, guar, trucking and fluid supplies. Our fuel costs consist primarily of diesel fuel used by our various trucks and other motorized equipment. The prices for fuel and the raw materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages. Historically, we have generally been able to pass along price increases to our customers; however, we may be unable to do so in the future. We do not engage in commodity price hedging activities.
Interest Rate Risk
We may be subject to interest rate risk on variable rate debt under our credit facility. The impact of a 1% increase in interest rates on our variable rate debt as of December 31, 2018, 2017 and 2016 would have resulted in an increase in interest expense and corresponding decrease in pre‑tax income of approximately $0.7 million, $0.2 million and $2.1 million, for the years ended December 31, 2018, 2017 and 2016, respectively.
Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk are trade receivables. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including credit evaluations and maintaining an allowance for doubtful accounts.


47


MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of ProPetro Holding Corp. is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. ProPetro Holding Corp. maintains a system of internal accounting controls designed to provide reasonable assurance, at a reasonable cost, that assets are safeguarded against loss or unauthorized use and that the financial records are adequate and can be relied upon to produce financial statements in accordance with accounting principles generally accepted in the United States of America. The internal control system is augmented by written policies and procedures, an internal audit program and the selection and training of qualified personnel. This system includes policies that require adherence to ethical business standards and compliance with all applicable laws and regulations.
There are inherent limitations to the effectiveness of any controls system. A controls system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the controls system are met. Also, no evaluation of controls can provide absolute assurance that all control issues and any instances of fraud, if any, within the Company will be detected. Further, the design of a controls system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The Company intends to continually improve and refine its internal controls.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operations of our internal control over financial reporting as of December 31, 2018 based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management’s assessment is that ProPetro Holding Corp. maintained effective internal control over financial reporting as of December 31, 2018. The independent registered public accounting firm, Deloitte & Touche LLP, has audited the consolidated financial statements as of and for the year ended December 31, 2018, and has also issued their report on the effectiveness of the Company’s internal control over financial reporting, included in this report on page 50.

 /s/ Dale Redman
Dale Redman
Chief Executive Officer and Director
(Principal Executive Officer)
    

 /s/ Jeffrey Smith
Jeffrey Smith
Chief Financial Officer
(Principal Financial Officer)

Midland, Texas
February 28, 2019

48




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of
ProPetro Holding Corp. and Subsidiary

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of ProPetro Holding Corp. and Subsidiary (the "Company") as of December 31, 2018 and 2017, the related consolidated statements of income, shareholders' equity and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with, accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019, expressed an unqualified opinion on the Company's internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2019
We have served as the Company's auditor since 2013.

49



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of
ProPetro Holding Corp. and Subsidiary

Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of ProPetro Holding Corp. and Subsidiary (the “Company”) as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Company and our report dated February 28, 2019, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2019



50


Item 8. Financial Statements and Supplementary Data.

PROPETRO HOLDING CORP. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2018 AND 2017
(In thousands, except share data)
 
2018
 
2017
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
132,700

 
$
23,949

Accounts receivable - net of allowance for doubtful accounts of $100 and $443, respectively
202,956

 
199,656

Inventories
6,353

 
6,184

Prepaid expenses
6,610

 
5,123

Other current assets
638

 
748

Total current assets
349,257

 
235,660

PROPERTY AND EQUIPMENT - Net of accumulated depreciation
912,846

 
470,910

OTHER NONCURRENT ASSETS:
 
 
 
Goodwill
9,425

 
9,425

Intangible assets - net of amortization
13

 
301

Deferred revenue rebate - net of amortization

 
615

Other noncurrent assets
2,981

 
2,121

Total other noncurrent assets
12,419

 
12,462

TOTAL ASSETS
$
1,274,522

 
$
719,032

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable
$
214,460

 
$
211,149

Accrued liabilities
138,089

 
16,607

Current portion of long-term debt

 
15,764

Accrued interest payable
211

 
76

Total current liabilities
352,760

 
243,596

DEFERRED INCOME TAXES
54,283

 
4,881

LONG-TERM DEBT
70,000

 
57,178

OTHER LONG-TERM LIABILITIES
124

 
125

Total liabilities
477,167

 
305,780

COMMITMENTS AND CONTINGENCIES (Note 17)


 


SHAREHOLDERS’ EQUITY:
 
 
 
Preferred stock, $0.001 par value, 30,000,000 shares authorized, none issued, respectively

 

Common stock, $0.001 par value, 200,000,000 shares authorized,100,190,126 and 83,039,854 shares issued, respectively
100

 
83

Additional paid-in capital
817,690

 
607,466

Accumulated deficit
(20,435
)
 
(194,297
)
Total shareholders’ equity
797,355

 
413,252

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
1,274,522

 
$
719,032


51


PROPETRO HOLDING CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED
DECEMBER 31, 2018, 2017 AND 2016
(In thousands, except per share data)
 
2018
 
2017
 
2016
REVENUE - Service revenue
$
1,704,562

 
$
981,865

 
$
436,920

COSTS AND EXPENSES:
 
 
 
 
 
Cost of services (exclusive of depreciation and amortization)
1,270,577

 
813,823

 
404,140

General and administrative (inclusive of stock‑based compensation)
53,958

 
49,215

 
26,613

Depreciation and amortization
88,138

 
55,628

 
43,542

Property and equipment impairment expense

 

 
6,305

Goodwill impairment expense

 

 
1,177

Loss on disposal of assets
59,220

 
39,086

 
22,529

Total costs and expenses
1,471,893

 
957,752

 
504,306

OPERATING INCOME (LOSS)
232,669

 
24,113

 
(67,386
)
OTHER INCOME (EXPENSE):
 
 
 
 
 
Interest expense
(6,889
)
 
(7,347
)
 
(20,387
)
Gain on extinguishment of debt

 

 
6,975

Other expense
(663
)
 
(1,025
)
 
(321
)
Total other income (expense)
(7,552
)
 
(8,372
)
 
(13,733
)
INCOME (LOSS) BEFORE INCOME TAXES
225,117

 
15,741

 
(81,119
)
INCOME TAX (EXPENSE)/BENEFIT
(51,255
)
 
(3,128
)
 
27,972

NET INCOME (LOSS)
$
173,862

 
$
12,613

 
$
(53,147
)
NET INCOME (LOSS) PER COMMON SHARE:
 
 
 
 
 
Basic
$
2.08

 
$
0.17

 
$
(1.19
)
Diluted
$
2.00

 
$
0.16

 
$
(1.19
)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
 
 
 
 
 
Basic
83,460

 
76,371

 
44,787

Diluted
87,046

 
79,583

 
44,787



See notes to consolidated financial statements. 52


PROPETRO HOLDING CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED
DECEMBER 31, 2018, 2017 AND 2016 (In thousands)
 
Preferred Stock
 
 
 
Common Stock
 
 
 
 
 
 
 
Shares
 
Amount
 
Preferred
Additional
Paid‑In
Capital
 
Shares
 
Amount
 
Additional
Paid‑In
Capital
 
Accumulated
Deficit
 
Total
BALANCE - January 1, 2016

 
$

 
$

 
34,621

 
$
35

 
$
223,299

 
$
(153,763
)
 
$
69,571

Stock‑based compensation cost

 

 

 

 

 
1,649

 

 
1,649

Additional equity capitalization, net of costs

 

 

 
18,007

 
18

 
40,407

 

 
40,425

Preferred equity capitalization, net of costs
17,000

 
17

 
162,494

 

 

 

 

 
162,511

Net loss

 

 

 

 

 

 
(53,147
)
 
(53,147
)
BALANCE - December 31, 2016
17,000

 
17

 
162,494

 
52,628

 
53

 
265,355

 
(206,910
)
 
221,009

Stock‑based compensation cost

 

 

 

 

 
9,489

 

 
9,489

Initial Public Offering net of costs

 

 

 
13,250

 
13

 
170,128

 

 
170,141

Conversion of preferred stock to common stock at Initial Public Offering
(17,000
)
 
(17
)
 
(162,494
)
 
17,000

 
17

 
162,494

 

 

Issuance of equity award—net

 

 

 
162

 

 

 

 

Net income

 

 

 

 

 

 
12,613

 
12,613

BALANCE - December 31, 2017

 

 

 
83,040

 
83

 
607,466

 
(194,297
)
 
413,252

Stock‑based compensation cost

 

 

 

 

 
5,482

 

 
5,482

Issuance of equity award—net

 

 

 
550

 
1

 
246

 

 
247

Issuance of common stock