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UNITED STATES

For the fiscal year ended December 31, 2018

For the transition period from                      to                     

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 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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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

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.

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.

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 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

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.

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.

We may become more leveraged and our indebtedness could adversely affect our operations and financial condition.

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.

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.

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.

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:

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.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Acquisition of Pioneer Pressure Pumping Assets

2018 Operational Highlights

Over the course of the year ended December 31, 2018, we:

2018 Financial Highlights

Among other financial highlights, for the year ended December 31, 2018:

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:

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.

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.

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

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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”). 

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016